STATE OF NEW JERSEY BOARD OF PUBLIC UTILITIES

Transcription

1 STATE OF NEW JERSEY BOARD OF PUBLIC UTILITIES IN THE MATTER OF THE PETITION OF ) NEW JERSEY NATURAL GAS COMPANY ) FOR THE ANNUAL REVIEW AND ) BPU DOCKET NO. GR1305 REVISION OF ITS BASIC GAS SUPPLY ) OAL DOCKET NO. SERVICE (BGSS) AND CONSERVATION ) INCENTIVE PROGRAM (CIP) FACTORS ) FOR F/Y 2014 )

2 I N D E X

3 INDEX Case Summary Petition Exhibit A BGSS Over/ Underrecovery Schedules (Seven Months Actual through April 2013 and Five Months Projected through September 2013) 1 Exhibit B BGSS Over/ Underrecovery Schedules (Projected Period October 2013 through September 2014) Exhibit C CIP Recovery Schedules Exhibit D Calculation of Revised Balancing Rate Exhibit E Impact of Proposed Rates on Typical Customers and Calculation of Overall BGSS Rate Exhibit F Proposed Tariff Pages Testimony: Jayana S. Shah Director - Gas Supply, NJNG Energy Services Tina M. Trebino Manager - Regulatory Affairs Anne-Marie Peracchio Director - Conservation and Clean Energy Policy 1 For ease of presentation, the filing contains BGSS schedules for the NJNG fiscal year (FY) 2013 and FY2014 (October 1-September 30). Actual BGSS schedules for FY2012 and projected BGSS schedules for FY2015 will be included in Workpapers to be filed under separate cover.

4 C A S E S U M M A R Y

5 CASE SUMMARY NEW JERSEY NATURAL GAS COMPANY ANNUAL REVIEW AND REVISION OF ITS BASIC GAS SUPPLY SERVICE (BGSS) AND CONSERVATION INCENTIVE PROGRAM (CIP) FACTORS FOR F/Y 2014 BASIS FOR REQUEST: FILING DATE: May 29, 2013 EFFECTIVE DATE: October 1, 2013 BASIC GAS SUPPLY SERVICE ( BGSS ) 1. On May 24, 2013, New Jersey Natural Gas Company (the Company ) submitted notification to the New Jersey Board of Public Utilities ( Board ) and the New Jersey Division of Rate Counsel ( Rate Counsel ) in BPU Docket Nos. GR and GX of its intent to decrease its Periodic BGSS price from the current pre-tax level of $ per therm to $ per therm effective June 1, This factor results in an effective pre-tax adjustment clause decrease of $ per therm of gas sales (an after-tax adjustment clause decrease of $ per therm), representing a 5.2 percent decrease for a residential heating customer using 100 therms per month. Within this proceeding, the Company proposes to maintain the pre-tax Periodic BGSS billing factor for sales customers of $ per therm. 2. While the Company has not yet made any determination of the need for additional BGSS price adjustments, the Company may seek to increase the BGSS price up to a maximum of 5 percent of the total residential bill on December 1, 2013 and/or February 1, 2014 pursuant to the Order in BPU Docket No. GX ( Generic BGSS Order ). If such an increase is required, the Company will provide notice to the Board and Rate Counsel of its election to adjust its BGSS rates upward as is required by the Generic BGSS Order. Additionally, pursuant to the Generic BGSS Order, the Company may decrease its BGSS rate, provide refunds or rate credits at any time upon five days notice and the filing of supporting documentation to the Board and to Rate Counsel. 3. The Company proposes to decrease its pre-tax Balancing Charge from its current pre-tax level of $ per therm to $ per therm. This factor results in an effective pretax decrease of $ per therm of gas sales effective October 1, 2013 (an after-tax decrease of $ per therm). All Balancing Charge revenues from transportation customers are credited to BGSS recoveries. For BGSS customers, the balancing charge is included as a component of the delivery charge and deducted from the BGSS charge in order to provide a BGSS Price-to-Compare.

6 CONSERVATION INCENTIVE PROGRAM ( CIP ) With this filing and pursuant to the December 12, 2006 and January 21, 2010 Orders in BPU Docket No. GR ( CIP Order ), the Company proposes to modify its after-tax CIP recovery rates as a component of delivery rates effective October 1, The existing rates, proposed rates and projected change in after-tax CIP recoveries for each CIP Group are: Group Group Description Existing Charge/ (Credit) per therm Proposed Charge per therm Change in Recovery $ million Group I Residential Non-Heat $ $ ($0.03) Group II Residential Heat $ $ ($4.99) Group III General Service - Small $ $ ($0.89) Group IV General Service - Large $ $ ($1.52) Total ($7.44) IMPACT TO CUSTOMERS The proposed October 1, 2013 CIP changes result in a 1.0 percent decrease to the total bill of an average residential heating sales customer (Group II), a 0.8 percent decrease for an average residential non-heat sales customer (Group I), a 2.0 percent decrease for an average sales customer in Group III and a 0.9 percent decrease for an average Group IV sales customer. The June 1, 2013 BGSS decrease and proposed CIP decrease for October 1, 2013 result in an overall combined decrease of $7.37 for a residential heating customer using 100 therms per month or 6.1 percent.

7 PETITION OF NEW JERSEY NATURAL GAS COMPANY FOR THE ANNUAL REVIEW AND REVISION OF ITS BASIC GAS SUPPLY SERVICE (BGSS) AND CONSERVATION INCENTIVE PROGRAM (CIP) FACTORS FOR F/Y 2014

8 STATE OF NEW JERSEY BOARD OF PUBLIC UTILITIES IN THE MATTER OF THE PETITION OF NEW JERSEY NATURAL GAS COMPANY FOR THE ANNUAL REVIEW AND REVISION OF ITS BASIC GAS SUPPLY SERVICE (BGSS) AND CONSERVATION INCENTIVE PROGRAM (CIP) FACTORS FOR F/Y 2014 ) ) ) ) ) ) BPU DOCKET NO. GR1305 PETITION TO: THE HONORABLE COMMISSIONERS OF THE NEW JERSEY BOARD OF PUBLIC UTILITIES Pursuant to the Order Approving BGSS Price Structure ( Generic BGSS Order ) issued on January 17, 2002 by the New Jersey Board of Public Utilities (the BPU or Board ) in BPU Docket No. GX , and the applicable provisions of N.J.S.A. 48:2-21, New Jersey Natural Gas Company ( NJNG or the Company ) hereby requests the Board to accept the Company s annual reconciliation filing for its Basic Gas Supply Service ( BGSS ), and approve the Company s related request to maintain the BGSS price applicable to residential and certain small commercial customers ( Periodic BGSS ) that the Company will implement effective June 1, NJNG also hereby requests that the Board approve, pursuant to N.J.S.A. 48:2-21 and the authority granted the Company in a BPU Order in Docket No. GR dated October 3, 2008 ( Base Case Order ), a decrease to its balancing charge to reflect updated costs. Additionally, pursuant to N.J.S.A. 48:2-21 and the authority granted the Company in BPU Orders in Docket No. GR dated December 12, 2006 and January 21, 2010 ( CIP Orders ), NJNG hereby requests that the Board accept the Company s filing related to the 1 The referenced BGSS Order contemplates that annual BGSS reconciliation filings are made by natural gas companies by June 1 of each year, with proposed BGSS price adjustments to be effective October 1 of each year, and authorizes two additional self-implementing rates adjustments (subject to limits) upon notice to the Board on November 1 and January 1 each year to take effect on December 1 and February 1 respectively. Pursuant to the same order, BGSS is priced on a monthly basis for large commercial and industrial customers. 2 On May 24, 2013, New Jersey Natural Gas Company (the Company ) submitted notification to the Board and the New Jersey Division of Rate Counsel in BPU Docket Nos. GR and GX of its intent to

9 Conservation Incentive Program ( CIP ) for the period from October 1, 2012 through September 30, 2013 and approve the Company s related request to decrease its CIP recovery rates for Group I Residential Non-Heat customers, Group II Residential Heat customers, Group III General Service Small customers, and Group IV General Service Large customers. 1. NJNG is a corporation duly organized under the laws of the State of New Jersey and is a public utility engaged in the distribution and transportation of natural gas subject to the jurisdiction of the Board. The Company s principal business office is located at 1415 Wyckoff Road, Wall Township, New Jersey Communications and correspondence relating to this filing should be sent to: Mark R. Sperduto, Senior Vice President, Regulatory Affairs Tracey Thayer, Esq., Director, Regulatory Affairs Counsel New Jersey Natural Gas Company 1415 Wyckoff Road, P.O. Box 1464 Wall, N.J (732) (Sperduto) (732) (Thayer) (732) (fax) 3. As required by the referenced Generic BGSS Order, the instant filing includes a reconciliation of actual versus estimated costs and revenues from the last Board approved rate change for natural gas commodity, storage and interstate transportation costs, including the costs and results of natural gas supplies set by hedges; projected rates supported by projected volumes, revenues, and commodity, transportation, storage and transaction costs, including the cost of natural gas supplies set by hedges; deferred balances and the timeframe over which such balances and related rates are to be collected or returned; a written explanation of the circumstances that caused any deferred balances to be accrued; and, a written explanation of any significant activities or trends which may affect costs for the prospective period. This filing also includes testimony, schedules, and data that, in addition to the materials required by the Generic BGSS Order, are responsive to and consistent with the recommended minimum filing requirements ( MFRs ) for annual BGSS filings. Additional information related to the MFRs will be provided within Workpapers to be filed shortly. decrease its BGSS rate effective June 1, 2013 from the current level of $ per therm to $ per therm inclusive of sales tax. 2

10 4. On May 24, 2013, NJNG submitted notification to the Board and Rate Counsel in BPU Docket Nos. GR and GX of its intent to decrease its BGSS price applicable to residential and small commercial customers, effective June 1, 2013, from its current level of $ per therm to $ per therm, inclusive of sales tax. The price decrease, pursuant to the terms of the Generic BGSS Order, results in a 5.2 percent decrease for a residential heating customer using 100 therms per month. Based on the information provided herein, the Company proposes to maintain the June 1, 2013 BGSS price of $ per therm. 5. The costs and recoveries associated with the BGSS price will have no net impact on NJNG s base revenues or return on investment, and will not change NJNG s income or rate of return. 6. NJNG is providing nineteen (19) months of actual BGSS data for the period October 1, 2011 through April 30, 2013, and projected data for the twenty-nine (29) month period May 1, 2013 through September 30, As approved by the Board in the Base Case Order, NJNG is authorized to adjust its balancing charge in the annual BGSS filing to reflect updated costs. The Company is proposing to decrease its after-tax balancing charge by $ per therm. All balancing charge revenues from transportation customers are credited to BGSS. For BGSS customers, the balancing charge is included as a component of the delivery charge and deducted from the BGSS charge in order to provide a BGSS Price-to-Compare. 8. Pursuant to the CIP Orders, the CIP provides for a rate adjustment related to changes in average use per customer when compared to a pre-established benchmark. Additionally, any recoveries sought by the Company must meet the Basic Gas Supply Service Savings Test and Earnings Test ( Tests ) established in the CIP Orders. 9. Based on actual data for the period October 1, 2012 through April 30, 2013, and projected data for the period May 1, 2013 through September 30, 2013, the CIP calculations for fiscal year 2013, including projected prior fiscal period over or underrecovery balances, result in the following recovery amounts: 1) a margin deficiency of approximately $0.01 million for Group I Residential Non-Heat customers; 2) a margin deficiency of approximately $10.0 million 3

11 for Group II Residential Heat customers; 3) a margin deficiency of approximately $1.8 million for Group III General Service Small customers; and, 4) a margin deficiency of approximately $7.1 million for Group IV General Service Large customers. 10. The testimony of Tina M. Trebino and Exhibit C within this filing demonstrate that NJNG is entitled to full recovery of such balances based on the Tests approved in the CIP Orders. Pursuant to the terms of the CIP Orders, the Company is proposing an effective date of October 1, 2013 for the following after-tax CIP rates which, as compared to existing charges, result in the following decreases per therm: Group Group Description Proposed Charge/ per therm Existing Charge per therm Decrease per therm Group I Residential Non-Heat $ $ ($0.0103) Group II Residential Heat $ $ ($0.0112) Group III General Service - Small $ $ ($0.0269) Group IV General Service - Large $ $ ($0.0113) 11. The proposed October 1, 2013 CIP changes result in a 0.8 percent decrease for an average residential non-heat sales customer (Group I), a $1.12 or 1.0 percent decrease to the total bill of a residential heating sales customer (Group II) using 100 therms per month, a 2.0 percent decrease for an average sales customer in Group III and a 0.9 percent decrease for an average Group IV sales customer. The June 1, 2013 BGSS decrease and proposed CIP decrease result in an overall combined decrease of $7.37 for a residential heating customer using 100 therms per month or 6.1 percent. 12. This filing is supported by and includes the testimonies of Jayana S. Shah- Director, Gas Supply, NJNG Energy Services; Tina M. Trebino-Manager, Regulatory Affairs; and Anne-Marie Peracchio-Director, Conservation and Clean Energy Policy. Additionally, annexed hereto and made a part of this Petition are the following exhibits and schedules: Exhibit A BGSS schedules for the twelve (12) month period ending September 30, 2013, using actual data for the period from October 1, 2012 through April 30, 2013 and projected data 4

12 for the period from May 1, 2013 through September 30, Actual BGSS schedules for fiscal year (FY) 2012 will be included in Workpapers to be filed shortly under separate cover. Exhibit B BGSS schedules for the twelve (12) month period from October 1, 2013 through September 30, 2014, using projected data for the entire period. 4 Projected BGSS schedules for FY2015 will be included in Workpapers to be filed shortly under separate cover. Exhibit C Exhibit D Exhibit E CIP Schedules Calculation of Balancing Charge Impact of Proposed Rate Changes along with a summary of all the adjustments and appropriate balances contained in Exhibits A and B as necessary to compute the proposed BGSS price. Exhibit F Proposed tariff pages for Petitioner s Tariff Gas Service, BPU No. 8-Gas 13. NJNG has served notice and a copy of this filing, together with a copy of the annexed exhibits and schedules and NJNG s supporting testimonies being filed herewith, upon Rate Counsel, 140 East Front Street, Trenton, New Jersey. 3 The projected data includes the May 8, 2013 NYMEX settlement prices as requested by BPU Staff. 4 Id. 5

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14 INDEX OF SCHEDULES: EXHIBIT A Seven Months Actual through April 2013 and Five Months Projected through September Under/(Over) Recovered Gas Costs 2a. Gas Costs 2b. Gas Cost Recoveries 2c. Total Gas Costs 3. Total Therm Sales 4a. Interruptible Sales 4b. Sales at Sayreville 4c. Sales at Forked River 4d. Interruptible Transportation 4e. Income Sharing Derived from Off System Sales 4f. Income Sharing Derived from Capacity Release 4g. Balancing Credits and Penalty Charges 4h. Ocean Peaking Power 4i. Financial Risk Management (FRM) Program 4j. Storage Incentive 5. Supplier Refunds and Miscellaneous Adjustments 6. Computation of Interest 1 For ease of presentation, the filing contains BGSS schedules for fiscal year (FY) 2013 and FY2014. Actual BGSS schedules for FY2012 and projected BGSS schedules for FY2015 will be included in Workpapers to be filed under separate cover.

15 Exhibit A Schedule 1 Page 1 of 1 NEW JERSEY NATURAL GAS COMPANY STATEMENT OF ESTIMATED UNDER/(OVER) RECOVERED GAS COSTS BGSS YEAR 2013 $(000) SCHEDULE 1 ACTUAL ESTIMATE Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jul-13 Aug-13 Sep-13 TOTAL 1. Under/(Over) Recovered Gas Costs Beg. of Period 1 7,053 7,288 6,146 5,513 3,952 5,416 7,595 4,041 2,311 1, , Net Cost Appl. To BGSS Sales (Sch 2a) 13,504 33,993 43,938 56,402 55,341 50,093 18,789 11,228 8,448 8,631 8,602 8, , BGSS Recoveries (Sch 2b) (11,487) (31,625) (40,511) (51,973) (48,586) (43,474) (19,417) (10,367) (6,648) (6,749) (6,601) (6,584) (284,023) 4. Under/(Over) Rec. Gas Costs - Current Period (L.2 - L.3) 2,017 2,368 3,426 4,429 6,755 6,619 (628) 861 1,800 1,883 2,001 1,986 33,516 Adjustments 5. Interruptible (Sch.4a) (1) (1) 6. Sayreville (Sch.4b) (5) (5) (5) (5) (5) (26) 7. Forked River (Sch.4c) (2) (0) 0 0 (5) 0 (0) (5) (5) (5) (5) (5) (32) 8. Transportation(Sch.4d) (146) (123) (144) (126) (138) (132) (109) (128) (124) (128) (128) (124) (1,548) 9. FRM Program (Sch 4i) Storage Incentive (Sch.4k) , Off-System Sales (Sch.4e) (356) (281) (542) (2,106) (1,672) (492) (302) (113) (156) (156) (142) (113) (6,431) 12. Capacity Rel. (Sch.4f ) (1,573) (1,770) (1,809) (1,809) (1,655) (1,809) (1,767) (1,821) (1,769) (1,821) (1,821) (1,769) (21,194) 13. Supplier Ref. and Misc. Adj.(Sch.5) (246) (246) 14. Balancing and Penalty (Sch.4g) (467) (1,257) (1,571) (2,020) (1,814) (1,732) (864) (434) (303) (313) (312) (303) (11,389) 15. Ocean Peaking Power (Sch.4h) (73) (169) (67) (71) (101) (112) (109) (83) (92) (127) (103) (92) (1,198) 16. Total Debits and Credits (L.5 through L.15) (1,783) (3,510) (4,060) (5,989) (5,291) (4,440) (2,926) (2,590) (2,453) (2,555) (2,517) (2,410) (40,524) 17. Under/(Over) Recov.Gas Costs. End of Period (L's.1,4,&16) 7,288 6,146 5,513 3,952 5,416 7,595 4,041 2,311 1, Adjustments to opening balance are captured on Schedule 5.

16 Exhibit A Schedule 2 Page 1 of 2 NEW JERSEY NATURAL GAS COMPANY STATEMENT OF ESTIMATED GAS COSTS AND RECOVERIES BGSS YEAR 2013 $(000) & (000)THERMS SCHEDULE 2a ACTUAL ESTIMATE COST OF GAS-CURRENT PERIOD Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jul-13 Aug-13 Sep-13 TOTAL Total Gas Costs 1 17,876 41,447 57,538 72,777 70,946 60,149 20,804 12,338 10,618 10,797 10,411 9, ,983 REDUCTIONS TO COST OF GAS Natural Gas Vehicles Interruptible (Sch.4a) Sayreville (Sch. 4b) Forked Rv.(Sch. 4c) Off System Sales (Sch.4e) 6,199 7,890 15,720 18,485 17,457 12,168 3,909 3,159 4,165 4,218 3,860 2,704 99,933 Capacity Release (Sch. 4f) (1,851) (2,083) (2,128) (2,128) (1,947) (2,128) (2,079) (2,143) (2,081) (2,143) (2,143) (2,081) (24,934) Storage Incentive Sales 1, ,806 Company Use Gas Total Reductions 4,373 7,453 13,600 16,375 15,605 10,056 2,015 1,110 2,170 2,166 1, ,444 Net Cost Appl.To BGSS Sales 13,504 33,993 43,938 56,402 55,341 50,093 18,789 11,228 8,448 8,631 8,602 8, ,539 (Sch.1.,L.2) GAS COST RECOVERIES SCHEDULE 2b BGSS Sales 18,728 50,922 64,950 83,828 78,608 70,088 30,995 16,479 11,528 11,682 11,413 11, ,608 A/C Sales Monthly BGSS Sales 2,672 5,727 7,091 8,823 8,533 7,741 3,737 2,391 1,683 1,737 1,737 1,686 53,559 FEED Periodic BGSS Sales 16,035 45,171 57,839 74,985 70,059 62,328 27,235 14,028 9,782 9,885 9,620 9, ,608 Recovery Rate $ per Therm: Periodic BGSS Rate A/C Rate Monthly BGSS Rate FEED Rate Recoveries: Periodic BGSS 10,012 28,205 36,115 46,821 43,745 38,918 17,005 8,759 5,537 5,595 5,445 5, ,613 A/C Monthly BGSS 1,465 3,410 4,388 5,144 4,833 4,548 2,402 1,580 1,082 1,126 1,131 1,098 32,207 FEED Total BGSS Recovery (Sch. 1, L. 3) 11,487 31,625 40,511 51,973 48,586 43,474 19,417 10,367 6,648 6,749 6,601 6, ,023 1 Total Gas Costs equals the sum of Total Allocated Costs on Schedule 2c and the non-production Company Use Gas. The non-production Company Use Gas is included in Total Gas Costs and removed in the Reduction to Gas Costs on Schedule 2a for no impact to the BGSS.

17 Exhibit A Schedule 2 Page 2 of 2 NEW JERSEY NATURAL GAS COMPANY TOTAL GAS COSTS BGSS YEAR 2013 SCHEDULE 2c ACTUAL ESTIMATE Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jul-13 Aug-13 Sep-13 Mdth Beginning of Month Storage Balance 22,207 25,639 23,586 19,769 13,078 5,939 2,356 5,563 8,788 11,942 15,117 16,832 Commodity Purchases 7,252 5,578 6,032 6,344 5,634 6,511 7,509 5,598 5,296 5,333 3,758 4,449 Sub-total of Available Supplies A 29,459 31,217 29,618 26,113 18,711 12,450 9,865 11,161 14,084 17,275 18,875 21,281 Less volumes with assigned cost allocations Off System Sales, Electric Gen, Interr.Sales, Other 1,899 2,472 3,974 4,821 4,730 3, A/C Sales Monthly BGSS Sales FEED Sales Company Use Non Prod Sales Sub-total of Assigned Cost Allocations B 2,169 3,049 4,687 5,708 5,589 4,060 1, ,168 1,174 1, Allocation WACOG Volume C = A - B 27,290 28,169 24,931 20,405 13,123 8,390 8,488 10,187 12,916 16,102 17,790 20,466 volume available for allocation $000 Beginning of Month Storage Balance 97, , ,544 85,754 57,053 26,964 12,536 23,179 35,968 48,572 61,406 67,908 Beginning of Month WACOG Inventory 47,782 52,443 47,404 37,869 27,078 15,219 2,355 6,793 10,620 15,310 19,893 24,618 Commodity Purchases 28,129 20,037 24,042 25,341 21,037 24,986 28,372 22,113 21,014 21,374 14,797 18,076 Demand Charges 7,004 7,701 8,163 7,925 7,944 7,856 7,503 6,841 6,898 6,841 6,841 6,898 Sub-total of Available Supplies D 180, , , , ,111 75,025 50,766 58,926 74,500 92, , ,501 Less volumes with assigned cost allocations Off System Sales, Electric Gen, Interr.Sales, Other 6,212 9,527 15,720 18,485 17,535 12,168 4,084 3,253 4,251 4,309 3,951 2,793 A/C Sales Monthly BGSS Sales 1,465 3,410 4,388 5,144 4,833 4,548 2,402 1,580 1,082 1,126 1,131 1,098 FEED Sales Sub-total of Assigned cost allocations E 7,686 12,947 20,116 23,638 22,377 16,725 6,496 4,860 5,362 5,463 5,108 3,920 Allocation WACOG Costs F = D - E 172, , , ,252 90,735 58,300 44,271 54,066 69,138 86,634 97, ,580 $ available for allocation $/dth WACOG G = F / C Mdth Periodic BGSS Sales 1,604 4,517 5,784 7,499 7,006 6,233 2,723 1, CoUse & UFG Periodic BGSS Sales & CoUse & UFG H 1,607 4,523 5,792 7,522 7,022 6,247 2,741 1, volume to be allocated $000 Periodic BGSS ($/dth WACOG * Periodic BGSS volume) I = G * H 10,178 28,490 37,413 49,122 48,552 43,409 14,298 7,478 5,256 5,335 5,302 5,361 allocated cost Plus assigned cost allocations Off System Sales, Electric Gen, Interr.Sales, Other 6,212 9,527 15,720 18,485 17,535 12,168 4,084 3,253 4,251 4,309 3,951 2,793 A/C Sales Monthly BGSS Sales 1,465 3,410 4,388 5,144 4,833 4,548 2,402 1,580 1,082 1,126 1,131 1,098 FEED Sales Sub-total of Assigned cost allocations J 7,686 12,947 20,116 23,638 22,377 16,725 6,496 4,860 5,362 5,463 5,108 3,920 Total Allocated Costs (Sch 2a Total Gas Costs) K = I + J 17,865 41,437 57,530 72,760 70,928 60,134 20,794 12,338 10,618 10,797 10,411 9,282 End of Month Storage Balance L 110, ,544 85,754 57,053 26,964 12,536 23,179 35,968 48,572 61,406 67,908 79,015 Total Allocated Costs & Storage Balances M = K+L 128, , , ,813 97,892 72,670 43,973 48,306 59,190 72,204 78,319 88,296 Current Month WACOG Inventory Activity N = D - M 52,443 47,404 37,869 27,078 15,219 2,355 6,793 10,620 15,310 19,893 24,618 29,204

18 Exhibit A Schedule 3 Page 1 of 1 NEW JERSEY NATURAL GAS COMPANY ESTIMATED THERM SALES BGSS YEAR 2013 (000)THERMS SCHEDULE 3 ACTUAL ESTIMATE Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jul-13 Aug-13 Sep-13 TOTAL Residential BGSS Sales 15,341 42,705 54,427 70,942 65,345 58,736 26,284 13,379 9,398 9,489 9,224 9, ,526 Residential Air Conditioning Total Residential Sales 15,341 42,705 54,427 70,942 65,345 58,736 26,284 13,384 9,403 9,493 9,227 9, ,546 C&I Monthly BGSS Sales 2,672 5,727 7,091 8,823 8,533 7,741 3,737 2,391 1,683 1,737 1,737 1,686 53,559 C&I Periodic BGSS Sales 695 2,465 3,412 4,044 4,714 3, ,082 Air Conditioning FEED Total Commercial & Industrial Sales 3,387 8,217 10,523 12,886 13,264 11,352 4,710 3,095 2,125 2,189 2,186 2,130 76,062 Total Firm Sales 18,728 50,922 64,950 83,828 78,608 70,088 30,995 16,479 11,528 11,682 11,413 11, ,608 Interruptible IGS (Sch. 4a) Sayreville (Sch. 4b) Forked River(Sch. 4c) Off System Sales(Sch. 4e) 18,952 21,008 39,745 48,206 47,190 32,813 9,583 7,078 9,732 9,732 8,847 6, ,079 Natural Gas Vehicles Total Non-Firm Sales 18,989 21,017 39,745 48,206 47,304 32,813 9,586 7,287 9,934 9,941 9,056 6, ,275 Total Sales 37,716 71, , , , ,901 40,581 23,766 21,462 21,623 20,469 17, ,883 Firm Transportation 5,044 10,580 12,830 16,310 14,323 13,853 7,536 4,614 3,604 3,676 3,657 3,546 99,575 Residential Transportation 1,852 5,442 7,142 9,437 8,832 8,162 3,858 1,624 1,009 1,036 1,031 1,005 50,429 Interruptible Transportation 2,970 2,512 2,950 2,589 2,867 2,708 2,563 2,605 2,521 2,605 2,605 2,521 32,016 Ocean Peaking Power 401 4, ,968 1,857 1,222 2,760 6,120 3,889 1,632 25,077 Total Transportation 10,268 22,786 23,097 28,408 26,752 26,691 15,815 10,065 9,893 13,437 11,181 8, ,097 Total Mtherms 47,984 94, , , , ,592 56,395 33,831 31,355 35,060 31,650 26, ,980

19 Exhibit A Schedule 4 Page 1 of 3 INTERRUPTIBLE SALES NEW JERSEY NATURAL GAS COMPANY STATEMENT OF ESTIMATED INCOME SHARING DERIVED FROM INTERRUPTIBLE SALES AND FROM SALES TO SAYREVILLE ELECTRIC GENERATION BGSS YEAR 2013 $(000) & (000)THERMS SCHEDULE 4a ACTUAL ESTIMATE Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jul-13 Aug-13 Sep-13 TOTAL Interruptible & IGS Revenues Less Tefa-Sls tax (2) (2) Less BPU/RC Assessment (0) (0) Net Revenue Interr. Sales (Sch.3) Loss Factor (2%) Rate per therm n/a Cost of Gas (Sch. 2a) Gross Margin Total Credit (Sch.1, L.5) SAYREVILLE SCHEDULE 4b Revenue Less BPU/RC Assessment (0) (0) (0) (0) (0) (1) Net Revenue Therm Sales (Sch. 3) Rate per therm n/a Cost of Gas (Sch. 2a) Total Credit (Sch.1, L.6)

20 Exhibit A Schedule 4 Page 2 of 3 NEW JERSEY NATURAL GAS COMPANY STATEMENT OF ESTIMATED INCOME SHARING DERIVED FROM SALES TO FORKED RIVER ELECTRIC GENERATION, & TRANSPORT FOR OTHERS BGSS YEAR 2013 $(000) & (000)THERMS SCHEDULE 4c ACTUAL ESTIMATE FORKED RIVER Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jul-13 Aug-13 Sep-13 TOTAL Revenue Less BPU/RC Assessment (0) (0) 0 0 (0) 0 (0) (0) (0) (0) (0) (0) (1) Net Revenue Therm Sales (Sch. 3) Loss Factor (2%) Rate per therm n/a Cost of Gas (Sch.2a) Total Credit (Sch.1, L.7) Interruptible Transportation & IT switch to Firm SCHEDULE 4d Revenue ,558 Less BPU/RC Assessment and RA (114) (100) (113) (102) (111) (106) (101) (80) (77) (80) (80) (77) (1,141) Less NJ Clean Energy, USF & EE (144) (121) (143) (125) (139) (131) (124) (125) (121) (130) (130) (126) (1,557) Less IT Cogen/Tefa & Sls tax (31) (26) (31) (26) (28) (27) (24) (24) (23) (24) (24) (23) (312) Gross Margin ,548 Customer 100%, Total Credit (Sch.1, L.8) ,548 FRM Program SCHEDULE 4i FRM Program - Gain (Loss) ,193 NJNG 15% (Sch.1, L.9) Storage Incentive SCHEDULE 4j Storage Gain (Loss) 4, , ,811 NJNG 20% (Sch.1, L.10) ,362

21 Exhibit A Schedule 4 Page 3 of 3 NEW JERSEY NATURAL GAS COMPANY STATEMENT OF ESTIMATED INCOME SHARING DERIVED FROM OFF-SYSTEM SALES, CAPACITY RELEASE, BALANCING CHARGES, & OCEAN PEAKING POWER BGSS YEAR 2013 $(000) & (000)THERMS SCHEDULE 4e ACTUAL ESTIMATE OFF-SYSTEM SALES Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jul-13 Aug-13 Sep-13 TOTAL Revenues 6,617 8,221 16,357 20,963 19,424 12,746 4,265 3,292 4,348 4,401 4,027 2, ,499 Net Revenue 6,617 8,221 16,357 20,963 19,424 12,746 4,265 3,292 4,348 4,401 4,027 2, ,499 Therm sales 18,952 21,008 39,745 48,206 47,190 32,813 9,583 7,078 9,732 9,732 8,847 6, ,079 Rate per therm COG Cost of Gas (Sch. 2a) 6,199 7,890 15,720 18,485 17,457 12,168 3,909 3,159 4,165 4,218 3,860 2,704 99,933 Net Margin ,477 1, ,566 Customer 85% ,106 1, ,431 (Sch.1,L 11) NJNG 15% ,135 Total Credit = Cost of Gas plus sharings 6,554 8,171 16,262 20,591 19,129 12,660 4,212 3,272 4,320 4,374 4,002 2, ,364 CAPACITY RELEASE SCHEDULE 4f Revenue 1,851 2,083 2,128 2,128 1,947 2,128 2,079 2,143 2,081 2,143 2,143 2,081 24,934 Customer 85% 1,573 1,770 1,809 1,809 1,655 1,809 1,767 1,821 1,769 1,821 1,821 1,769 21,194 (Sch.1.,L 12) BALANCING CREDITS & PENALTY CHARGES SCHEDULE 4g Current Month MBR Penalty Charges Current Month Balancing Charges 467 1,257 1,571 2,020 1,814 1, ,386 0 Total Credit (Sch.1.,L 14) 467 1,257 1,571 2,020 1,814 1, ,389 OCEAN PEAKING POWER SCHEDULE 4h Therm Sales (Sch. 3) 401 4, ,968 1,857 1,222 2,760 6,120 3,889 1,632 25,077 Revenue ,285 Less Sales Tax (5) (12) (5) (5) (7) (8) (8) (6) (6) (9) (7) (6) (84) Less BPU/RC Assessment (0) (0) (0) (0) (0) (0) (0) (0) (0) (0) (0) (0) (3) Less USF Less RA, NJ Clean Energy, EE Less Balancing Charges Sharing Margin ,198 Customer 100% ,198 Balancing Charges Total Credit (Sch.1, L.15) ,198

22 Exhibit A Schedule 5 Page 1 of 1 NEW JERSEY NATURAL GAS COMPANY STATEMENT OF ESTIMATED SUPPLIER REFUNDS AND MISCELLANEOUS ADJUSTMENTS BGSS YEAR 2013 $(000) SCHEDULE 5 (Sch 1. LINE 13) Opening balance BGSS Interest Sch Adjustments to BGSS opening balance are captured on Schedule 1 OCT NOV DEC JAN FEB MAR 2013 Columbia Modernization Refund APR MAY JUN JUL AUG SEP T O T A L S 246

23 Exhibit A Schedule 6 Page 1 of 1 COMBINED $(000) SCHEDULE 6 DATE BALANCE AVERAGE ANNUAL ANNUAL SEP ,053 NEW JERSEY NATURAL GAS COMPANY BGSS YEAR 2013 COMPUTATION OF INTEREST ON UNDER/(OVER) RECOVERED BALANCES BALANCE RATE RATE 7.76% OCT ,288 7, % 46 NOV ,146 6, % 43 DEC ,513 5, % 38 JAN ,952 4, % 31 FEB ,416 4, % 30 MAR ,595 6, % 42 APR ,041 5, % 38 MAY ,311 3, % 21 JUN ,658 1, % 13 JUL , % 9 AUG % 5 SEP % TOTAL INTEREST TO BE CREDITED TO CUSTOMER 0

24 INDEX OF SCHEDULES: EXHIBIT B Projected October September Under/(Over) Recovered Gas Costs 2a. Gas Costs 2b. Gas Cost Recoveries 2c. Total Gas Costs 3. Total Therm Sales 4a. Interruptible Sales 4b. Sales at Sayreville 4c. Sales at Forked River 4d. Interruptible Transportation 4e. Income Sharing Derived from Off System Sales 4f. Income Sharing Derived from Capacity Release 4g. Balancing Credits and Penalty Charges 4h. Ocean Peaking Power 4i. Financial Risk Management (FRM) Program 4j. Storage Incentive 5. Supplier Refunds and Miscellaneous Adjustments 6. Computation of Interest 1 For ease of presentation, the filing contains BGSS schedules for fiscal year (FY) 2013 and FY2014. Actual BGSS schedules for FY2012 and projected BGSS schedules for FY2015 will be included in Workpapers to be filed under separate cover.

25 Exhibit B Schedule 1 Page 1 of 1 ESTIMATE NEW JERSEY NATURAL GAS COMPANY STATEMENT OF ESTIMATED UNDER/(OVER) RECOVERED GAS COSTS BGSS YEAR 2014 $(000) SCHEDULE 1 Oct-13 Nov-13 Dec-13 Jan-14 Feb-14 Mar-14 Apr-14 May-14 Jun-14 Jul-14 Aug-14 Sep-14 TOTAL 1. Under/(Over) Recovered Gas Costs Beg. of Period 1 46 (893) (2,156) (3,237) (3,628) (1,332) 3,048 2,741 2,420 2,218 2,006 1, Net Cost Appl. To BGSS Sales (Sch 2a) 14,570 28,215 48,807 60,042 52,635 44,871 21,536 11,592 8,644 8,827 8,691 8, , BGSS Recoveries (Sch 2b) (12,755) (26,352) (45,768) (55,560) (46,372) (37,061) (19,378) (9,734) (6,786) (6,890) (6,740) (6,721) (280,117) 4. Under/(Over) Rec. Gas Costs - Current Period (L.2 - L.3) 1,815 1,862 3,039 4,482 6,263 7,809 2,158 1,859 1,858 1,937 1,950 1,926 36,958 Adjustments 5. Interruptible (Sch.4a) Sayreville (Sch.4b) (0) (0) (0) (0) (0) (0) (5) (5) (5) (5) (5) (5) (34) 7. Forked River (Sch.4c) (1) (1) (1) (1) (1) (1) (5) (5) (5) (5) (5) (5) (37) 8. Transportation(Sch.4d) (137) (132) (137) (137) (124) (137) (125) (128) (124) (128) (128) (124) (1,559) 9. FRM Program (Sch 4i) Storage Incentive (Sch.4k) Off-System Sales (Sch.4e) (113) (113) (425) (850) (425) (113) (113) (113) (156) (156) (142) (113) (2,833) 12. Capacity Rel. (Sch.4f ) (1,819) (1,700) (1,740) (1,740) (1,620) (1,740) (1,387) (1,427) (1,387) (1,427) (1,427) (1,387) (18,800) 13. Supplier Ref. and Misc. Adj.(Sch.5) Balancing and Penalty (Sch.4g) (580) (1,074) (1,742) (2,077) (1,725) (1,361) (763) (418) (292) (301) (300) (291) (10,925) 15. Ocean Peaking Power (Sch.4h) (103) (104) (75) (67) (73) (76) (67) (83) (92) (127) (103) (92) (1,060) 16. Total Debits and Credits (L.5 through L.15) (2,754) (3,125) (4,121) (4,872) (3,968) (3,429) (2,465) (2,180) (2,060) (2,149) (2,111) (2,017) (35,249) 17. Under/(Over) Recov.Gas Costs. End of Period (L's.1,4,&16) (893) (2,156) (3,237) (3,628) (1,332) 3,048 2,741 2,420 2,218 2,006 1,846 1,754 1,754 1 Adjustments to opening balance are captured on Schedule 5.

26 Exhibit B Schedule 2 Page 1 of 2 ESTIMATE NEW JERSEY NATURAL GAS COMPANY STATEMENT OF ESTIMATED GAS COSTS AND RECOVERIES BGSS YEAR 2014 $(000) & (000)THERMS SCHEDULE 2a COST OF GAS-CURRENT PERIOD Oct-13 Nov-13 Dec-13 Jan-14 Feb-14 Mar-14 Apr-14 May-14 Jun-14 Jul-14 Aug-14 Sep-14 TOTAL Total Gas Costs 1 15,094 30,019 53,235 71,177 57,292 46,392 23,118 13,129 11,428 11,603 11,089 9, ,471 REDUCTIONS TO COST OF GAS Natural Gas Vehicles Interruptible (Sch.4a) Sayreville (Sch. 4b) Forked Rv.(Sch. 4c) Off System Sales (Sch.4e) 2,650 3,789 6,460 13,166 6,548 3,553 3,125 3,123 4,326 4,360 3,984 2,789 57,873 Capacity Release (Sch. 4f) (2,140) (2,000) (2,047) (2,047) (1,906) (2,047) (1,632) (1,679) (1,632) (1,679) (1,679) (1,632) (22,118) 0 Total Reductions 524 1,804 4,428 11,135 4,657 1,522 1,582 1,537 2,785 2,775 2,399 1,248 36,396 Net Cost Appl.To BGSS Sales 14,570 28,215 48,807 60,042 52,635 44,871 21,536 11,592 8,644 8,827 8,691 8, ,075 (Sch.1.,L.2) GAS COST RECOVERIES SCHEDULE 2b BGSS Sales 22,023 45,571 78,999 95,823 79,996 63,986 33,570 16,827 11,731 11,894 11,621 11, ,637 A/C Sales Monthly BGSS Sales 3,427 5,967 9,226 10,751 9,075 7,429 4,353 2,498 1,723 1,783 1,783 1,731 59,745 FEED Periodic BGSS Sales 18,570 39,578 69,714 85,012 70,864 56,497 29,159 14,237 9,913 10,018 9,750 9, ,082 Recovery Rate $ per Therm: Periodic BGSS Rate A/C Rate Monthly BGSS Rate FEED Rate Recoveries: Periodic BGSS 10,511 22,401 39,458 48,117 40,109 31,977 16,504 8,058 5,611 5,670 5,518 5, ,464 A/C Monthly BGSS 2,233 3,940 6,283 7,416 6,237 5,057 2,847 1,634 1,132 1,178 1,182 1,147 40,285 FEED Total BGSS Recovery (Sch. 1, L. 3) 12,755 26,352 45,768 55,560 46,372 37,061 19,378 9,734 6,786 6,890 6,740 6, ,117 1 Total Gas Costs equals the sum of Total Allocated Costs on Schedule 2c and the non-production Company Use Gas. The non-production Company Use Gas is included in Total Gas Costs and removed in the Reduction to Gas Costs on Schedule 2a for no impact to the BGSS.

27 Exhibit B Schedule 2 Page 2 of 2 NEW JERSEY NATURAL GAS COMPANY TOTAL GAS COSTS BGSS YEAR 2014 ESTIMATE SCHEDULE 2c Oct-13 Nov-13 Dec-13 Jan-14 Feb-14 Mar-14 Apr-14 May-14 Jun-14 Jul-14 Aug-14 Sep-14 Mdth Beginning of Month Storage Balance 19,506 22,678 21,127 15,771 9,688 4, ,905 5,536 9,052 12,683 16,314 Commodity Purchases 5,977 3,841 3,893 6,215 3,831 3,455 5,489 6,038 5,679 5,811 5,695 5,312 Sub-total of Available Supplies A 25,483 26,519 25,020 21,987 13,519 7,626 5,980 7,944 11,215 14,863 18,378 21,626 Less volumes with assigned cost allocations Off System Sales, Electric Gen, Interr.Sales, Other ,378 2,752 1, A/C Sales Monthly BGSS Sales , FEED Sales Company Use Non Prod Sales Sub-total of Assigned Cost Allocations B 952 1,449 2,306 3,833 2,291 1,509 1, ,175 1,182 1, Allocation WACOG Volume C = A - B 24,530 25,070 22,714 18,153 11,229 6,117 4,810 6,956 10,040 13,681 17,286 20,804 volume available for allocation $000 Beginning of Month Storage Balance 79,015 92,047 86,034 65,132 40,423 18,913 4,768 10,834 27,109 42,953 59,406 75,911 Beginning of Month WACOG Inventory 29,204 32,163 32,579 26,080 16,844 6,968 (1,731) 155 4,729 10,106 15,389 20,708 Commodity Purchases 24,242 17,185 18,642 30,039 18,583 16,356 23,487 26,436 25,067 25,797 25,373 23,618 Demand Charges 6,844 7,236 7,193 7,193 7,322 7,193 7,583 7,541 7,583 7,541 7,541 7,583 Sub-total of Available Supplies D 139, , , ,444 83,173 49,430 34,108 44,967 64,488 86, , ,820 Less volumes with assigned cost allocations Off System Sales, Electric Gen, Interr.Sales, Other 2,664 3,804 6,475 13,182 6,562 3,569 3,214 3,216 4,416 4,454 4,078 2,880 A/C Sales Monthly BGSS Sales 2,233 3,940 6,283 7,416 6,237 5,057 2,847 1,634 1,132 1,178 1,182 1,147 FEED Sales Sub-total of Assigned cost allocations E 4,908 7,755 12,785 20,625 12,825 8,653 6,088 4,891 5,592 5,674 5,300 4,071 Allocation WACOG Costs F = D - E 134, , , ,819 70,348 40,777 28,020 40,076 58,896 80, , ,749 $ available for allocation $/dth WACOG G = F / C Mdth Periodic BGSS Sales 1,857 3,958 6,971 8,501 7,086 5,650 2,916 1, , CoUse & UFG Periodic BGSS Sales & CoUse & UFG H 1,859 3,962 6,978 8,511 7,098 5,662 2,924 1, , volume to be allocated $000 Periodic BGSS ($/dth WACOG * Periodic BGSS volume) I = G * H 10,186 22,264 40,450 50,552 44,467 37,740 17,030 8,238 5,836 5,928 5,790 5,824 allocated cost Plus assigned cost allocations Off System Sales, Electric Gen, Interr.Sales, Other 2,664 3,804 6,475 13,182 6,562 3,569 3,214 3,216 4,416 4,454 4,078 2,880 A/C Sales Monthly BGSS Sales 2,233 3,940 6,283 7,416 6,237 5,057 2,847 1,634 1,132 1,178 1,182 1,147 FEED Sales Sub-total of Assigned cost allocations J 4,908 7,755 12,785 20,625 12,825 8,653 6,088 4,891 5,592 5,674 5,300 4,071 Total Allocated Costs (Sch 2a Total Gas Costs) K = I + J 15,094 30,019 53,235 71,177 57,292 46,392 23,118 13,129 11,428 11,603 11,089 9,895 End of Month Storage Balance L 92,047 86,034 65,132 40,423 18,913 4,768 10,834 27,109 42,953 59,406 75,911 91,864 Total Allocated Costs & Storage Balances M = K+L 107, , , ,600 76,205 51,160 33,952 40,238 54,382 71,008 87, ,759 Current Month WACOG Inventory Activity N = D - M 32,163 32,579 26,080 16,844 6,968 (1,731) 155 4,729 10,106 15,389 20,708 26,061

28 Exhibit B Schedule 3 Page 1 of 1 NEW JERSEY NATURAL GAS COMPANY ESTIMATED THERM SALES BGSS YEAR 2014 (000)THERMS SCHEDULE 3 ESTIMATE Oct-13 Nov-13 Dec-13 Jan-14 Feb-14 Mar-14 Apr-14 May-14 Jun-14 Jul-14 Aug-14 Sep-14 TOTAL Residential BGSS Sales 17,529 37,266 65,359 79,655 66,435 53,100 27,732 13,571 9,519 9,613 9,345 9, ,501 Residential Air Conditioning Total Residential Sales 17,529 37,266 65,359 79,655 66,435 53,100 27,732 13,577 9,524 9,616 9,348 9, ,520 C&I Monthly BGSS Sales 3,427 5,967 9,226 10,751 9,075 7,429 4,353 2,498 1,723 1,783 1,783 1,731 59,745 C&I Periodic BGSS Sales 1,041 2,313 4,355 5,357 4,430 3,397 1, ,581 Air Conditioning FEED Total Commercial & Industrial Sales 4,494 8,305 13,640 16,167 13,561 10,886 5,839 3,251 2,207 2,277 2,273 2,216 85,117 Total Firm Sales 22,023 45,571 78,999 95,823 79,996 63,986 33,570 16,827 11,731 11,894 11,621 11, ,637 Interruptible IGS (Sch. 4a) Sayreville (Sch. 4b) Forked River(Sch. 4c) Off System Sales(Sch. 4e) 6,038 8,463 13,745 27,491 13,745 7,566 7,078 7,078 9,732 9,732 8,847 6, ,708 Natural Gas Vehicles Total Non-Firm Sales 6,071 8,495 13,778 27,524 13,775 7,599 7,280 7,287 9,934 9,941 9,056 6, ,139 Total Sales 28,094 54,066 92, ,346 93,771 71,584 40,851 24,114 21,665 21,835 20,677 17, ,776 Firm Transportation 5,904 9,778 14,746 17,086 14,496 11,791 7,132 4,614 3,687 3,759 3,740 3, ,362 Residential Transportation 2,432 4,892 8,514 10,373 8,518 6,566 3,543 1,624 1,009 1,036 1,031 1,005 50,543 Interruptible Transportation 2,756 2,667 2,756 2,756 2,490 2,756 2,521 2,605 2,521 2,605 2,605 2,521 31,559 Ocean Peaking Power 1,622 1, ,222 2,760 6,120 3,889 1,632 20,097 Total Transportation 12,714 18,985 26,259 30,293 25,700 21,640 13,358 10,065 9,976 13,520 11,264 8, ,561 Total Mtherms 40,808 73, , , ,472 93,224 54,209 34,179 31,641 35,355 31,941 26, ,337

29 Exhibit B Schedule 4 Page 1 of 3 INTERRUPTIBLE SALES NEW JERSEY NATURAL GAS COMPANY STATEMENT OF ESTIMATED INCOME SHARING DERIVED FROM INTERRUPTIBLE SALES AND FROM SALES TO SAYREVILLE ELECTRIC GENERATION BGSS YEAR 2014 $(000) & (000)THERMS SCHEDULE 4a ESTIMATE Oct-13 Nov-13 Dec-13 Jan-14 Feb-14 Mar-14 Apr-14 May-14 Jun-14 Jul-14 Aug-14 Sep-14 TOTAL Interruptible & IGS Revenues Less Tefa-Sls tax Less BPU/RC Assessment Net Revenue Interr. Sales (Sch.3) Loss Factor (2%) Rate per therm n/a Cost of Gas (Sch. 2a) Gross Margin Total Credit (Sch.1, L.5) SAYREVILLE SCHEDULE 4b Revenue Less BPU/RC Assessment (0) (0) (0) (0) (0) (0) (0) (0) (0) (0) (0) (0) (1) Net Revenue Therm Sales (Sch. 3) Rate per therm n/a Cost of Gas (Sch. 2a) Total Credit (Sch.1, L.6)

30 Exhibit B Schedule 4 Page 2 of 3 NEW JERSEY NATURAL GAS COMPANY STATEMENT OF ESTIMATED INCOME SHARING DERIVED FROM SALES TO FORKED RIVER ELECTRIC GENERATION, & TRANSPORT FOR OTHERS BGSS YEAR 2014 $(000) & (000)THERMS SCHEDULE 4c ESTIMATE FORKED RIVER Oct-13 Nov-13 Dec-13 Jan-14 Feb-14 Mar-14 Apr-14 May-14 Jun-14 Jul-14 Aug-14 Sep-14 TOTAL Revenue Less BPU/RC Assessment (0) (0) (0) (0) (0) (0) (0) (0) (0) (0) (0) (0) (1) Net Revenue Therm Sales (Sch. 3) Loss Factor (2%) Rate per therm n/a Cost of Gas (Sch.2a) Total Credit (Sch.1, L.7) Interruptible Transportation & IT switch to Firm SCHEDULE 4d Revenue ,370 Less BPU/RC Assessment and RA (85) (82) (85) (85) (77) (85) (78) (80) (77) (80) (80) (77) (971) Less NJ Clean Energy, USF & EE (137) (133) (137) (137) (124) (137) (126) (130) (126) (130) (130) (126) (1,573) Less IT Cogen/Tefa & Sls tax (26) (25) (26) (23) (21) (23) (20) (21) (20) (21) (21) (20) (268) Gross Margin ,559 Total Credit (Sch.1, L.8) ,559 FRM Program SCHEDULE 4i FRM Program - Gain (Loss) NJNG 15% (Sch.1, L.9) Storage Incentive SCHEDULE 4j Storage Gain (Loss) NJNG 20% (Sch.1, L.10)

31 Exhibit B Schedule 4 Page 3 of 3 NEW JERSEY NATURAL GAS COMPANY STATEMENT OF ESTIMATED INCOME SHARING DERIVED FROM OFF-SYSTEM SALES, CAPACITY RELEASE, BALANCING CHARGES, & OCEAN PEAKING POWER BGSS YEAR 2014 $(000) & (000)THERMS SCHEDULE 4e ESTIMATE OFF-SYSTEM SALES Oct-13 Nov-13 Dec-13 Jan-14 Feb-14 Mar-14 Apr-14 May-14 Jun-14 Jul-14 Aug-14 Sep-14 TOTAL Revenues 2,783 3,923 6,960 14,166 7,048 3,687 3,258 3,256 4,510 4,544 4,150 2,922 61,206 Net Revenue 2,783 3,923 6,960 14,166 7,048 3,687 3,258 3,256 4,510 4,544 4,150 2,922 61,206 Therm sales 6,038 8,463 13,745 27,491 13,745 7,566 7,078 7,078 9,732 9,732 8,847 6, ,708 Rate per therm COG Cost of Gas (Sch. 2a) 2,650 3,789 6,460 13,166 6,548 3,553 3,125 3,123 4,326 4,360 3,984 2,789 57,873 Net Margin , ,333 Customer 85% ,833 (Sch.1,L 11) NJNG 15% Total Credit = Cost of Gas plus sharings 2,763 3,903 6,885 14,016 6,973 3,667 3,238 3,236 4,482 4,516 4,125 2,902 60,706 CAPACITY RELEASE SCHEDULE 4f Revenue 2,140 2,000 2,047 2,047 1,906 2,047 1,632 1,679 1,632 1,679 1,679 1,632 22,118 Customer 85% 1,819 1,700 1,740 1,740 1,620 1,740 1,387 1,427 1,387 1,427 1,427 1,387 18,800 (Sch.1.,L 12) BALANCING CREDITS & PENALTY CHARGES SCHEDULE 4g Current Month MBR Penalty Charges Current Month Balancing Charges 580 1,074 1,742 2,077 1,725 1, ,925 0 Total Credit (Sch.1.,L 14) 580 1,074 1,742 2,077 1,725 1, ,925 OCEAN PEAKING POWER SCHEDULE 4h Therm Sales (Sch. 3) 1,622 1, ,222 2,760 6,120 3,889 1,632 20,097 Revenue ,138 Less Sales Tax (7) (7) (5) (5) (5) (5) (5) (6) (6) (9) (7) (6) (74) Less BPU/RC Assessment (0) (0) (0) (0) (0) (0) (0) (0) (0) (0) (0) (0) (3) Less USF Less RA, NJ Clean Energy, EE Less Balancing Charges Sharing Margin ,060 Customer 100% ,060 Balancing Charges Total Credit (Sch.1, L.15) ,060

32 Exhibit B Schedule 5 Page 1 of 1 NEW JERSEY NATURAL GAS COMPANY STATEMENT OF ESTIMATED SUPPLIER REFUNDS AND MISCELLANEOUS ADJUSTMENTS BGSS YEAR 2014 $(000) SCHEDULE 5 (Sch 1. LINE 13) Opening balance BGSS Interest Sch Adjustments to BGSS opening balance are captured on Schedule 1 OCT NOV DEC JAN FEB MAR APR MAY JUN JUL AUG SEP T O T A L S -

33 Exhibit B Schedule 6 Page 1 of 1 NEW JERSEY NATURAL GAS COMPANY BGSS YEAR 2014 COMPUTATION OF INTEREST ON UNDER/(OVER) RECOVERED BALANCES COMBINED $(000) SCHEDULE 6 DATE BALANCE AVERAGE ANNUAL ANNUAL SEP BALANCE RATE RATE 7.76% OCT 2013 (893) (424) % (3) NOV 2013 (2,156) (1,524) % (10) DEC 2013 (3,237) (2,696) % (17) JAN 2014 (3,628) (3,432) % (22) FEB 2014 (1,332) (2,480) % (16) MAR , % 6 APR ,741 2, % 19 MAY ,420 2, % 17 JUN ,218 2, % 15 JUL ,006 2, % 14 AUG ,846 1, % 12 SEP ,754 1, % TOTAL INTEREST TO BE CREDITED TO CUSTOMER 0

34 EXHIBIT C CONSERVATION INCENTIVE PROGRAM (CIP) SCHEDULES INDEX OF SCHEDULES: 1. Results and Calculation of Rate for Group I Residential Non-Heat 2. Results and Calculation of Rate for Group II Residential Heat 3. Results and Calculation of Rate for Group III General Service - Small 4. Results and Calculation of Rate for Group IV General Service - Large 5. Weather Related Margin Deficiency 6. BGSS Savings Test 7. ROE Test

35 Exhibit C Schedule 1 Page 1 of 3 New Jersey Natural Gas Company Conservation Incentive Program Group I: Residential Non-Heat FY2013 Actual per Books 1 Actual/ Total Class Number of Actual Avg. Baseline Aggregate Margin Margin Customer Class Estimate Therms Customers Use / Cust. Use / Cust. 2 Difference Therm Impact Factor 4 Variance (a) (b) (c) (d) = (b) / (c) (e) (f) = (d) - (e) (g) = (f) * (c) Residential Non-Heating October a 222,112 17, (6.9) (119,338) $ ($36,494) November a 211,993 14, (10.1) (149,223) $ ($45,633) December a 352,487 16, ,273 $ $2,836 January a 414,790 16, ,150 $ $13,501 February a 341,047 16, ,177 $ $15,650 March a 343,671 16, ,274 $ $18,432 April a 249,006 16, ,835 $ $38,175 May e 193,165 16, ,648 $ $16,100 June e 300,652 17, ,286 $ $24,762 July e 334,993 17, (0.4) (7,052) $ ($2,230) August e 303,663 17, (0.4) (6,700) $ ($2,119) September e 349,904 17, ,496 $ $3,320 Total 3,617, ,826 $46,299 Margin Revenue Factor / Therm Per Tariff Sheet No. 179 Margin Deficiency/ (Credit) $ (46,299) Prior Period (Over) / Under Recovery 3 $ 60,638 Total Deficiency/(Credit) $ 14,339 Projected Residential Non-Heating Throughput for Recovery Period 3,135,234 Pre-tax CIP Charge/(Credit) $ BPU/RC Assessment Factor CIP Charge/(Credit) including assessments $ % Sales Tax $ Proposed After-tax CIP Charge/(Credit) per Therm $ Current After-tax CIP Charge/(Credit) per Therm $ Increase/ (Decrease) in After-tax CIP Charge/(Credit) per Therm $ (0.0103) 1 Per Exhibit C, Schedule 1, Page 2 2 Per Tariff Sheet No Per Exhibit C, Schedule 1, Page 3 4 The margin factor has been increased effective June 1, 2013 to reflect the base rates agreed to by Board Staff, Rate Counsel and the Company in a stipulation in BPU Docket No. GR which is currently pending BPU approval.

36 Exhibit C Schedule 1 Page 2 of 3 New Jersey Natural Gas Company Customers and Therms Group I: RS non-heat Actual Actual Actual Actual Actual Actual Actual Estimate Estimate Estimate Estimate Estimate Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jul-13 Aug-13 Sep-13 Customers RS non-heat sales 16,262 13,632 14,998 15,525 15,214 15,017 14,944 15,567 16,152 16,267 16,271 16,132 RS non-heat transport 1,159 1,172 1,271 1,326 1,348 1,362 1,395 1,362 1,362 1,362 1,362 1,362 Total Customers 17,422 14,804 16,269 16,851 16,562 16,379 16,340 16,929 17,514 17,629 17,633 17,494 Volumes RS non-heat sales 199, , , , , , , , , , , ,898 3,280,225 RS non-heat transport 22,791 20,723 45,575 38,698 39,065 38,789 30,353 19,971 19,719 20,762 20,806 20, ,258 Total Volumes 222, , , , , , , , , , , ,904 3,617,483

37 Exhibit C Schedule 1 Page 3 of 3 Exhibit C Schedule 1 Page 3 of 3 NEW JERSEY NATURAL GAS COMPANY STATEMENT OF ESTIMATED UNDER/(OVER) RECOVERED CIP BALANCE GROUP I - RS NON-HEAT FY2013 Actual Actual Actual Actual Actual Actual Actual Estimate Estimate Estimate Estimate Estimate Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jul-13 Aug-13 Sep-13 TOTAL Beginning Under/(Over) Recovery $ 112, , , ,837 94,947 90,104 85,224 81,688 78,945 74,676 69,919 65, ,763 Therm Sales 222, , , , , , , , , , , ,904 3,617,483 Pre-tax Recovery Rate per Therm Recovery $ 3,911 3,010 5,005 5,890 4,843 4,880 3,536 2,743 4,269 4,757 4,312 4,969 52,125 Ending Under/(Over) Recovery $ 108, , ,837 94,947 90,104 85,224 81,688 78,945 74,676 69,919 65,607 60,638 60,638

38 Exhibit C Schedule 2 Page 1 of 3 New Jersey Natural Gas Company Conservation Incentive Program Group II: Residential Heat FY2013 Actual per Books 1 Actual/ Total Class Number of Actual Avg. Baseline Aggregate Margin Margin Customer Class Estimate Therms Customers Use / Cust. Use / Cust. 2 Difference Therm Impact Factor 4 Variance (a) (b) (c) (d) = (b) / (c) (e) (f) = (d) - (e) (g) = (f) * (c) Residential Heating October a 16,970, , (13.2) (5,901,440) $ ($1,804,660) November a 47,935, , ,745,364 $ $2,062,732 December a 61,216, , (29.7) (13,102,157) $ ($4,006,640) January a 79,963, , (11.7) (5,245,069) $ ($1,603,942) February a 73,835, , (1.1) (473,656) $ ($144,844) March a 66,553, , ,482,625 $ $1,676,587 April a 29,893, , (10.5) (4,682,976) $ ($1,432,054) May e 14,815, , (8.0) (3,553,620) $ ($1,086,697) June e 10,110, , (2.7) (1,217,693) $ ($385,156) July e 10,193, , (1.3) (562,403) $ ($177,888) August e 9,953, , (1.3) (589,717) $ ($186,528) September e 9,915, , (3.9) (1,757,290) $ ($555,831) Total 431,357, ,028.3 (24,858,033) ($7,644,921) Margin Revenue Factor / Therm Per Tariff Sheet No. 179 Margin Deficiency/ (Credit) $ 7,644,921 Prior Period (Over) / Under Recovery 3 $ 2,308,299 Total Deficiency/(Credit) $ 9,953,220 Projected Residential Heating Throughput for Recovery Period 445,927,699 Pre-tax CIP Charge/(Credit) $ BPU/RC Assessment Factor CIP Charge/(Credit) including assessments $ % Sales Tax $ Proposed After-tax CIP Charge/(Credit) per Therm $ Current After-tax CIP Charge/(Credit) per Therm $ Increase/ (Decrease) in After-tax CIP Charge/(Credit) per Therm $ (0.0112) 1 Per Exhibit C, Schedule 2, Page 2 2 Per Tariff Sheet No Per Exhibit C, Schedule 2, Page 3 4 The margin factor has been increased effective June 1, 2013 to reflect the base rates agreed to by Board Staff, Rate Counsel and the Company in a stipulation in BPU Docket No. GR which is currently pending BPU approval.

39 Exhibit C Schedule 2 Page 2 of 3 Exhibit C Schedule 2 Page 2 of 3 New Jersey Natural Gas Company Customers and Therms Group II: RS heat Actual Actual Actual Actual Actual Actual Actual Estimate Estimate Estimate Estimate Estimate Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jul-13 Aug-13 Sep-13 Customers RS heat sales 405, , , , , , , , , , , ,496 RS heat transport 43,434 44,237 46,365 48,019 48,740 49,651 50,507 49,651 49,651 49,651 49,651 49,651 Total Customers 448, , , , , , , , , , , ,148 Volumes RS heat sales 15,141,432 42,514,099 54,120,289 70,565,627 65,042,575 58,430,841 26,065,805 13,210,887 9,121,805 9,178,295 8,943,664 8,930, ,265,584 RS heat transport 1,828,956 5,421,362 7,096,397 9,398,067 8,792,877 8,123,100 3,827,992 1,604, ,962 1,015,296 1,009, ,929 50,091,974 Total Volumes 16,970,387 47,935,462 61,216,686 79,963,694 73,835,452 66,553,942 29,893,797 14,815,041 10,110,767 10,193,592 9,953,543 9,915, ,357,558

40 Exhibit C Schedule 2 Page 3 of 3 Exhibit C Schedule 2 Page 3 of 3 NEW JERSEY NATURAL GAS COMPANY STATEMENT OF ESTIMATED UNDER/(OVER) RECOVERED CIP BALANCE GROUP II - RS HEAT FY2013 Actual Actual Actual Actual Actual Actual Actual Estimate Estimate Estimate Estimate Estimate Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jul-13 Aug-13 Sep-13 TOTAL Beginning Under/(Over) Recovery $ 16,339,182 15,941,637 14,364,560 12,350,531 9,719,726 7,290,540 5,100,915 4,117,409 3,629,994 3,297,350 2,961,981 2,634,509 16,339,182 Therm Sales 16,970,387 47,935,462 61,216,686 79,963,694 73,835,452 66,553,942 29,893,797 14,815,041 10,110,767 10,193,592 9,953,543 9,915, ,357,558 Pre-tax Recovery Rate per Therm Recovery $ 397,545 1,577,077 2,014,029 2,630,806 2,429,186 2,189, , , , , , ,210 14,030,883 Ending Under/(Over) Recovery $ 15,941,637 14,364,560 12,350,531 9,719,726 7,290,540 5,100,915 4,117,409 3,629,994 3,297,350 2,961,981 2,634,509 2,308,299 2,308,299

41 Exhibit C Schedule 3 Page 1 of 3 New Jersey Natural Gas Company Conservation Incentive Program Group III: General Service Small FY2013 Actual per Books 1 Actual/ Total Class Number of Actual Avg. Baseline Aggregate Margin Margin Customer Class Estimate Therms Customers Use / Cust. Use / Cust. 2 Difference Therm Impact Factor 4 Variance (a) (b) (c) (d) = (b) / (c) (e) (f) = (d) - (e) (g) = (f) * (c) General Service Small October a 959,148 25, (42.2) (1,079,386) $ ($285,929) November a 3,314,339 25, ,458 $ $202,505 December a 4,487,215 26, (44.8) (1,187,745) $ ($314,634) January a 5,550,155 26, (48.4) (1,301,097) $ ($344,660) February a 6,149,880 27, (7.9) (212,626) $ ($56,325) March a 4,882,236 27, (7.2) (195,982) $ ($51,916) April a 1,471,629 26, (42.1) (1,130,836) $ ($299,558) May e 912,569 26, (12.6) (330,545) $ ($87,561) June e 557,050 26, (3.5) (91,422) $ ($25,397) July e 575,006 25, (5.2) (134,676) $ ($37,413) August e 574,600 25, (15.7) (405,055) $ ($112,524) September e 556,638 25, ,323 $ $49,260 Total 29,990,466 1, ,320.0 (5,127,589) ($1,364,153) Margin Revenue Factor / Therm Per Tariff Sheet No. 179 Margin Deficiency/ (Credit) $ 1,364,153 Prior Period (Over) / Under Recovery 3 $ 430,185 Total Deficiency/(Credit) $ 1,794,337 Projected Commercial Throughput for Recovery Period 33,109,837 Pre-tax CIP Charge/(Credit) $ BPU/RC Assessment Factor CIP Charge/(Credit) including assessments $ % Sales Tax $ Proposed After-tax CIP Charge/(Credit) per Therm $ Current After-tax CIP Charge/(Credit) per Therm $ Increase/ (Decrease) in After-tax CIP Charge/(Credit) per Therm $ (0.0269) 1 Per Exhibit C, Schedule 3, Page 2 2 Per Tariff Sheet No Per Exhibit C, Schedule 3, Page 3 4 The margin factor has been increased effective June 1, 2013 to reflect the base rates agreed to by Board Staff, Rate Counsel and the Company in a stipulation in BPU Docket No. GR which is currently pending BPU approval.

42 Exhibit C Schedule 3 Page 2 of 3 Exhibit C Schedule 3 Page 2 of 3 New Jersey Natural Gas Company Customers and Therms Group III: GSS Actual Actual Actual Actual Actual Actual Actual Estimate Estimate Estimate Estimate Estimate Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jul-13 Aug-13 Sep-13 Customers GSS Sales 20,195 20,045 20,839 21,096 21,205 21,200 21,002 20,611 20,319 20,172 20,056 20,084 GSS A/C GSS Transport 5,375 5,451 5,634 5,780 5,813 5,836 5,846 5,727 5,727 5,727 5,727 5,727 Total Customers 25,608 25,524 26,506 26,910 27,052 27,069 26,886 26,338 26,046 25,899 25,783 25,811 Volumes GSS Sales 688,007 2,461,719 3,409,739 4,037,979 4,710,253 3,587, , , , , , ,306 22,051,839 GSS A/C 6,260 3,489 1,649 5,362 3,807 4,961 1,350 26,879 GSS Transport 264, ,130 1,075,827 1,506,813 1,435,820 1,289, , , , , , ,332 7,911,748 Total Volumes 959,148 3,314,339 4,487,215 5,550,155 6,149,880 4,882,236 1,471, , , , , ,638 29,990,466

43 Exhibit C Schedule 3 Page 3 of 3 Exhibit C Schedule 3 Page 3 of 3 NEW JERSEY NATURAL GAS COMPANY STATEMENT OF ESTIMATED UNDER/(OVER) RECOVERED CIP BALANCE GROUP III - GENERAL SERVICE SMALL FY2013 Actual Actual Actual Actual Actual Actual Actual Estimate Estimate Estimate Estimate Estimate Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jul-13 Aug-13 Sep-13 TOTAL Beginning Under/(Over) Recovery $ 2,799,175 2,735,271 2,472,113 2,115,828 1,675,146 1,186, , , , , , ,382 2,799,175 Therm Sales 959,148 3,314,339 4,487,215 5,550,155 6,149,880 4,882,236 1,471, , , , , ,638 29,990,466 Pre-tax Recovery Rate per Therm Recovery $ 63, , , , , , ,847 72,458 44,230 45,656 45,623 44,197 2,368,991 Ending Under/(Over) Recovery $ 2,735,271 2,472,113 2,115,828 1,675,146 1,186, , , , , , , , ,185

44 Exhibit C Schedule 4 Page 1 of 3 New Jersey Natural Gas Company Conservation Incentive Program Group IV: General Service Large FY2013 Actual per Books 1 Large Adjusted Actual/ Total Class Number of Customer Number of Actual Avg. Baseline Aggregate Margin Margin Customer Class Estimate Therms Customers Adjustment Customers Use / Cust. 2 Use / Cust. Difference Therm Impact Factor 4 Variance (a) (b) (c1) (c2) (c) = (c1) + (c2) (d) = (b) / (c) (e) (f) = (d) - (e) (g) = (f) * (c) General Service Large October a 6,536,359 8, , ,059.1 (341.7) (3,112,772) $ ($647,457) November a 14,025,836 8, ,048 1, ,026.2 (476.0) (4,306,250) $ ($895,700) December a 17,593,271 9, ,244 1, ,591.6 (688.5) (6,364,602) $ ($1,323,837) January a 21,893,614 9, ,293 2, ,012.6 (656.7) (6,103,242) $ ($1,269,474) February a 19,854,608 9, ,285 2, ,687.9 (549.5) (5,102,462) $ ($1,061,312) March a 18,871,127 9, ,272 2, ,090.8 (55.6) (515,545) $ ($107,233) April a 9,658,339 9, ,124 1, ,251.1 (192.5) (1,756,206) $ ($365,291) May e 5,658,684 8, , (176.3) (1,590,209) $ ($330,763) June e 4,043,801 8, , (114.0) (1,024,310) $ ($223,197) July e 4,178,251 8, , (75.1) (673,616) $ ($146,781) August e 4,178,793 8, , (18.9) (169,281) $ ($36,886) September e 4,046,572 8, , (180.9) (1,624,646) $ ($354,010) Total 130,539,256 14, ,744.6 (32,343,142) ($6,761,943) Margin Revenue Factor / Therm Per Tariff Sheet No. 179 Margin Deficiency/ (Credit) $ 6,761,943 Prior Period (Over) / Under Recovery 3 $ 372,034 Total Deficiency/(Credit) $ 7,133,977 Projected Commercial Throughput for Recovery Period 134,662,514 Pre-tax CIP Charge/(Credit) $ BPU/RC Assessment Factor CIP Charge/(Credit) including assessments $ % Sales Tax $ Proposed After-tax CIP Charge/(Credit) per Therm $ Current After-tax CIP Charge/(Credit) per Therm $ Increase/ (Decrease) in After-tax CIP Charge/(Credit) per Therm $ (0.0113) 1 Per Exhibit C, Schedule 4, Page 2 2 Per Tariff Sheet No Per Exhibit C, Schedule 4, Page 3 4 The margin factor has been increased effective June 1, 2013 to reflect the base rates agreed to by Board Staff, Rate Counsel and the Company in a stipulation in BPU Docket No. GR which is currently pending BPU approval.

45 Exhibit C Schedule 4 Page 2 of 3 Exhibit C Schedule 4 Page 2 of 3 New Jersey Natural Gas Company Customers and Therms Group IV: GSL Actual Actual Actual Actual Actual Actual Actual Estimate Estimate Estimate Estimate Estimate Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jul-13 Aug-13 Sep-13 Customers GSL Sales 4,925 4,856 4,982 5,012 5,014 4,994 4,936 4,918 4,883 4,865 4,853 4,867 GSL A/C GSL Transport 3,994 4,000 4,069 4,086 4,078 4,086 4,081 4,014 4,014 4,014 4,014 4,014 Total Customers 8,940 8,877 9,070 9,118 9,112 9,099 9,037 8,931 8,896 8,878 8,866 8,880 Volumes GSL Sales 2,651,870 5,637,462 7,044,967 8,736,870 8,423,252 7,652,773 3,701,986 2,371,513 1,613,123 1,666,550 1,667,092 1,615,894 52,783,352 GSL A/C 13,733 23,220 27,558 32,330 75,493 60,209 42, ,987 GSL Transport 3,870,756 8,365,154 10,520,746 13,124,415 11,355,862 11,158,145 5,913,911 3,287,170 2,430,678 2,511,701 2,511,701 2,430,678 77,480,917 Total Volumes 6,536,359 14,025,836 17,593,271 21,893,614 19,854,608 18,871,127 9,658,339 5,658,684 4,043,801 4,178,251 4,178,793 4,046, ,539,256

46 Exhibit C Schedule 4 Page 3 of 3 Exhibit C Schedule 4 Page 3 of 3 NEW JERSEY NATURAL GAS COMPANY STATEMENT OF ESTIMATED UNDER/(OVER) RECOVERED CIP BALANCE GROUP IV - GENERAL SERVICE LARGE FY2013 Actual Actual Actual Actual Actual Actual Actual Estimate Estimate Estimate Estimate Estimate Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jul-13 Aug-13 Sep-13 TOTAL Beginning Under/(Over) Recovery $ 8,611,476 8,258,618 7,366,575 6,247,643 4,855,209 3,592,456 2,392,252 1,777,982 1,418,090 1,160, , ,396 8,611,476 Therm Sales 6,536,359 14,025,836 17,593,271 21,893,614 19,854,608 18,871,127 9,658,339 5,658,684 4,043,801 4,178,251 4,178,793 4,046, ,539,256 Pre-tax Recovery Rate per Therm Recovery $ 352, ,043 1,118,932 1,392,434 1,262,753 1,200, , , , , , ,362 8,239,442 Ending Under/(Over) Recovery $ 8,258,618 7,366,575 6,247,643 4,855,209 3,592,456 2,392,252 1,777,982 1,418,090 1,160, , , , ,034

47 Exhibit C Schedule 5 Page 1 of 1 New Jersey Natural Gas Company Conservation Incentive Program Weather Normalization Calculation for the Winter Period Group II RS/RT Heat DEGREE DEGREE CUSTOMERS IN CONSUMPTION ACTUAL DAYS DAYS CONSUMPTION CONSUMPTION FACTOR CUSTOMERS CONSUMPTION TOTAL MARGIN MARGIN WNC 1 ACTUAL VARIANCE FACTOR 1 FACTOR USE PER CUST ACTUAL FACTOR THERMS FACTOR 2 IMPACT Oct-12 a (79) 47, , ,438 50,244 (3,969,256) $ ($1,213,799) Nov-12 a , , ,907 62,509 7,688,649 $ $2,351,189 Dec-12 a (159) 72, , ,596 75,444 (11,995,546) $ ($3,668,238) Jan-13 a (61) 77, , ,531 81,254 (4,956,509) $ ($1,515,700) Feb-13 a (10) 71, , ,845 74,877 (748,772) $ ($228,975) Mar-13 a , , ,105 72,247 4,696,084 $ $1,436,063 Apr-13 a (28) 66, , ,573 69,021 (1,932,590) $ ($590,986) May-13 e (3) 53, , ,875 56,557 (169,671) $ ($51,885) TOTAL 4,744 4,592 (152) (11,387,610) ($3,482,331) Group III GSS DEGREE DEGREE CUSTOMERS IN CONSUMPTION ACTUAL DAYS DAYS CONSUMPTION CONSUMPTION FACTOR CUSTOMERS CONSUMPTION TOTAL MARGIN MARGIN WNC 1 ACTUAL VARIANCE FACTOR 1 FACTOR USE PER CUST ACTUAL FACTOR THERMS FACTOR 2 IMPACT Oct-12 a (79) 4,405 26, ,608 4,237 (334,755) $ ($88,677) Nov-12 a ,224 27, ,524 3, ,943 $ $129,786 Dec-12 a (159) 6,086 27, ,506 5,893 (937,033) $ ($248,220) Jan-13 a (61) 6,879 27, ,910 6,726 (410,258) $ ($108,677) Feb-13 a (10) 6,918 27, ,052 6,768 (67,678) $ ($17,928) Mar-13 a ,235 27, ,069 6, ,080 $ $105,186 Apr-13 a (28) 4,667 27, ,886 4,563 (127,750) $ ($33,841) May-13 e (3) 4,010 27, ,338 3,912 (11,735) $ ($3,109) TOTAL 4,744 4,592 (152) (1,002,187) ($265,479) Group IV GSL DEGREE DEGREE CUSTOMERS IN CONSUMPTION ACTUAL DAYS DAYS CONSUMPTION CONSUMPTION FACTOR CUSTOMERS CONSUMPTION TOTAL MARGIN MARGIN WNC 1 ACTUAL VARIANCE FACTOR 1 FACTOR USE PER CUST ACTUAL FACTOR THERMS FACTOR 2 IMPACT Oct-12 a (79) 13,070 7, ,111 16,626 (1,313,474) $ ($273,203) Nov-12 a ,930 7, ,048 21,133 2,599,308 $ $540,656 Dec-12 a (159) 18,299 7, ,244 23,012 (3,658,928) $ ($761,057) Jan-13 a (61) 19,152 7, ,293 24,187 (1,475,413) $ ($306,886) Feb-13 a (10) 17,801 7, ,285 22,521 (225,211) $ ($46,844) Mar-13 a ,305 7, ,272 21,699 1,410,460 $ $293,376 Apr-13 a (28) 14,840 7, ,124 18,392 (514,967) $ ($107,113) May-13 e (3) 13,831 7, ,019 17,245 (51,734) $ ($10,761) TOTAL 4,744 4,592 (152) (3,229,958) ($671,831) Total TOTAL MARGIN All Groups THERMS IMPACT Oct-12 a (5,617,486) ($1,575,678) Nov-12 a 10,777,900 $3,021,631 Dec-12 a (16,591,507) ($4,677,515) Jan-13 a (6,842,179) ($1,931,263) Feb-13 a (1,041,661) ($293,746) Mar-13 a 6,503,624 $1,834,625 Apr-13 a (2,575,307) ($731,940) May-13 e (233,139) ($65,754) TOTAL (15,619,755) ($4,419,642) 1 Degree Days and Consumption factors are per Tariff Sheet No. 169 approved in BPU Docket No. GR Per Tariff Sheet No. 179 NOTE: The Weather Normalization Clause is currently suspended. This schedule is only provided for the purpose of calculating the weather related component of the usage variance of the CIP clause.

48 Exhibit C Schedule 6 Page 1 of 8 New Jersey Natural Gas Company Conservation Incentive Program Filing Year ended September 30, 2013 GR1305 Calculation of BGSS Savings for October 2013 through September 2014 Recovery Period Recurring initial savings identified 1 $2,799,799 Savings from extension of recurring initial savings 2 $1,418,276 Additional Savings 3 $217,305 Additional Savings 4 $7,993,500 Additional Savings 5 $1,032,957 Total BGSS Savings Available for CIP comparison $13,461, Refer to Exhibit E of the January 14, 2010 stipulation in BPU Docket No. GR approved by the BPU on January 20, The value of the Tennessee contracts have been modified to reflect the impact of the Tennessee rate case on Contract and Contract Refer to Exhibit C to this Petition, Schedule 6, p The release agreements identified as recurring initial savings in footnote 1 were set to expire on March 31, The Company has extended these agreements through March 31, Refer to Exhibit C to this Petition, Schedule 6, p NJNG has generated additional BGSS savings of $217,305 for CIP purposes beginning in fiscal year 2012 by not renewing a contract for 10,000 dekatherms per day of winterseason-only firm transportation capacity on Dominion Transmission, Inc., that expired on March 31, Refer to Exhibit C to this Petition, Schedule 6, p. 7. NJNG has generated additional BGSS savings for CIP purposes by not renewing 30,000 dth per day of TETCO capacity at the maximum daily demand rate of $0.73 per dth. Refer to Exhibit C to this Petition, Schedule 6, p. 6. NJNG has generated additional BGSS savings of $1,032,957 for CIP purposes beginning in fiscal year 2013 by restrucuring a contract and reducing the volume by 20,000 dekatherms per day of firm transportation capacity on Dominion Transmission, Inc. Refer to Exhibit C to this Petition, Schedule 6, p. 7.

49 Exhibit C Schedule 6 Page 2 of 8 New Jersey Natural Gas Company Conservation Incentive Program Filing Year ended September 30, 2013 GR1305 Summary Group I Per Exhibit C, Schedule 1 ($46,299) a Group II Per Exhibit C, Schedule 2 $7,644,921 b Group III Per Exhibit C, Schedule 3 $1,364,153 c Group IV Per Exhibit C, Schedule 4 $6,761,943 d CIP Calculation for current period $15,724,718 e=a+b+c+d Weather Related Value of CIP Per Exhibit C, Schedule 5 $4,419,642 f CIP Value subject to BGSS test-current year $11,305,076 g=e-f Prior Year Carry-over CIP Value Per Exhibit C, Schedule 6, Page 4 of 8 $0 h Total CIP Value subject to BGSS savings comparison $11,305,076 i=g-h BGSS Savings Per Exhibit C, Schedule 6, Page 1 of 8 $13,461,838 j Non-weather CIP Value to be recovered in current year Total CIP value subject to recovery for current year CIP Carry-over value to next year $11,305,076 k= full value of i if j>i k=j, if j<i $15,724,718 l=f+k $0 m=i-j, if i>j m=0, if i<j

50 Exhibit C Schedule 6 Page 3 of 8 New Jersey Natural Gas Company Conservation Incentive Program Filing Year ended September 30, 2012 Calculation of BGSS Savings for October 2012 through September 2013 Recovery Period Recurring initial savings identified 1 $4,218,075 Savings from extension of recurring initial savings 2 $1,426,069 Additional Savings 3 $217,305 Additional Savings 4 $7,993,500 Additional Savings 5 $1,032,957 Total BGSS Savings Available for CIP comparison $14,887, Refer to Exhibit E of the January 14, 2010 stipulation in BPU Docket No. GR approved by the BPU on January 20, The value of the Tennessee contracts have been modified to reflect the impact of the Tennessee rate case on Contract and Contract Refer to Exhibit C to this Petition, Schedule 6, p The release agreements identified as recurring initial savings in footnote 1 were set to expire on March 31, The Company has extended these agreements through March 31, 2014 adding $1,426,069 to BGSS Savings for October 2012 through September 2013 CIP year. Refer to Exhibit C to this Petition, Schedule 6, p As agreed to by the Parties in the Final Stipulation in BPU Docket No. GR and approved by the BPU on April 27, 2011, NJNG has generated additional BGSS savings of $217,305 for CIP purposes beginning in fiscal year 2012 by not renewing a contract for 10,000 Per NJNG's March 22, 2011 notification letter of its reduction to fixed capacity costs by not renewing 30,000 dth per day of TETCO capacity at the maximum daily demand rate of $0.73 per dth. Refer to Exhibit C to this Petition, Schedule 6, p As discussed in the testimony of Tina M. Trebino in BPU Docket No. GR , NJNG has generated additional BGSS savings of $1,032,957 for CIP purposes beginning in fiscal year 2013 by restrucuring a contract and reducing the volume by 20,000 dekatherms per day of firm transportation capacity on Dominion Transmission, Inc. Refer to Exhibit C to this Petition, Schedule 6, p. 7.

51 Exhibit C Schedule 6 Page 4 of 8 New Jersey Natural Gas Company Conservation Incentive Program Filing Year ended September 30, 2012 Summary Group I Group II Group III Group IV CIP Calculation for current period Weather Related Value of CIP CIP Value subject to BGSS test-current year Prior Year Carry-over CIP Value Total CIP Value subject to BGSS savings comparison BGSS Savings Non-weather CIP Value to be recovered in current year Total CIP value subject to recovery for current year CIP Carry-over value to next year $165,892 a $31,421,041 b $3,453,328 c $9,948,453 d $44,988,714 e=a+b+c+d $30,243,340 f $14,745,374 g=e-f $0 h $14,745,374 i=g-h $14,887,907 j $14,745,374 k= full value of i if j>i k=j, if j<i $44,988,714 l=f+k $0 m=i-j, if i>j m=0, if i<j

52 Exhibit C Schedule 6 Page 5 of 8 New Jersey Natural Gas CIP BGSS Savings The following contract restructurings are consistent with the accompanying explanation of BGSS Savings in Paragraph 17 of the January 14, 2010 Stipulation in BPU Docket No. GR approved by the BPU on January 21, The capacity releases described below are being released to NJRES. The total values for each transaction have been separated into three categories as described below: Recurring Initial Savings Identified - Savings identified in the January 14, 2010 Stipulation in BPU Docket No. GR revised for the impact of the Tennessee Rate Case in Section III. Savings From Extension - Savings from the extension of various releases included in the Recurring Initial Savings Identified. Additional Savings - Savings identified for new transactions since the January 21, 2010 approval. I. Waddington to South Commack Iroquois Capacity NJNG has permanently released 15,000 dth of Iroquois capacity from Waddington to South Commack. This release is at maximum rates. (Contract ) Recurring CIP Recovery Release Total Initial Savings Savings from Additional Year Days Quantity Rate Value Identified Extension Savings ,000 $ $ 1,996,185 $ 1,996,185 $ - $ ,000 $ $ 1,996,185 $ 1,996,185 $ - $ ,000 $ $ 2,001,654 $ 2,001,654 $ - $ ,000 $ $ 1,996,185 $ 1,996,185 $ - $ ,000 $ $ 1,996,185 $ 1,996,185 $ - $ - II. Transco Capacity A. NJNG released 5,000 dth of Transco capacity from CNG Leidy to Transco Z6 NNY. This release is at maximum rates for a term beginning January 1, 2010 through March 31, (Contract ) UPDATE: Release has been extended through March 31, 2014 at a fixed rate. B. C. Recurring CIP Recovery Release Total Initial Savings Savings from Additional Year Days Quantity Rate Value Identified Extension Savings ,000 $ $ 162,026 $ 162,026 $ - $ ,000 $ $ 216,628 $ 216,628 $ - $ ,000 $ $ 217,221 $ 217,221 $ - $ ,000 $ $ 216,628 $ 108,017 $ 108,611 $ ,000 $ $ 108,017 $ - $ 108,017 $ - NJNG released 3,250 dth of Transco capacity from National Fuel Wharton to Transco Z6 NNY. This release is at maximum rates for a term beginning January 1, 2010 through March 31, (Contract ) UPDATE: Release has been extended through March 31, 2014 at a fixed rate. Recurring CIP Recovery Release Total Initial Savings Savings from Additional Year Days Quantity Rate Value Identified Extension Savings ,250 $ $ 105,317 $ 105,317 $ - $ ,250 $ $ 140,808 $ 140,808 $ - $ ,250 $ $ 141,194 $ 141,194 $ - $ ,250 $ $ 140,808 $ 70,211 $ 70,597 $ ,250 $ $ 70,211 $ - $ 70,211 $ - NJNG released 10,350 dth of Transco capacity from CNG Leidy to Transco Z6 NNY. This release is at maximum rates for a term beginning January 1, 2010 through March 31, (Contract ) UPDATE: Release has been extended through March 31, 2014 at a fixed rate. Recurring CIP Recovery Release Total Initial Savings Savings from Additional Year Days Quantity Rate Value Identified Extension Savings ,350 $ $ 335,393 $ 335,393 $ - $ ,350 $ $ 448,419 $ 448,419 $ - $ ,350 $ $ 449,647 $ 449,647 $ - $ ,350 $ $ 448,419 $ 223,595 $ 224,824 $ ,350 $ $ 223,595 $ - $ 223,595 $ -

53 Exhibit C Schedule 6 Page 6 of 8 III. Tennessee Capacity A. NJNG released 11,000 dth of Tennessee capacity from Tennessee Z5 East Aurora to Tennessee Z4 Browns Run. This release is for a term beginning January 1, 2010 through March 31, (Contract 64306). UPDATE: Contract was terminated January 8, Savings continue at Tennessee rate case approved rates. B. Recurring CIP Recovery Release Total Initial Savings Savings from Additional Year Days Quantity Rate Value Identified Extension Savings ,000 $ $ 59,237 $ 59,237 $ - $ ,000 $ $ 79,200 $ 79,200 $ - $ ,000 $ $ 607,184 $ 607,184 $ - $ ,000 $ $ 803,614 $ 803,614 $ - $ ,000 $ $ 803,614 $ 803,614 $ - $ - NJNG released 10,728 dth of Tennessee capacity from Tennessee Z4 Stagecoach to Tennessee Z5 Ramsey. This release is for a term beginning January 1, 2010 through March 31, (Contract 64307, subsequently updated to and currently 92392). UPDATE: 2012 and 2013 values have been updated for Tennessee rate case approved rates. Release has been extended through March 31, Recurring CIP Recovery Release Total Initial Savings Savings from Additional Year Days Quantity Rate Value Identified Extension Savings ,728 $ $ 816,518 $ 816,518 $ - $ ,728 $ $ 1,091,681 $ 1,091,681 $ - $ ,728 $ $ 669,614 $ 669,614 $ - $ ,728 $ $ 494,964 $ 246,804 $ 248,160 $ ,728 $ $ 246,804 $ - $ 246,804 $ - IV. Texas Eastern Capacity A. NJNG released 10,000 dth of Texas Eastern capacity from CNG Leidy (5,000 dth) and Chambersburg (5,000 dth) to Texas Eastern M3. This release is at maximum rates for a term beginning January 1, 2010 through March 31, (Contract ) UPDATE: Release has been extended through March 31, 2014 at a fixed rate. Recurring CIP Recovery Release Total Initial Savings Savings from Additional Year Days Quantity Rate Value Identified Extension Savings ,000 $ $ 458,012 $ 458,012 $ - $ ,000 $ $ 612,361 $ 612,361 $ - $ ,000 $ $ 614,038 $ 614,038 $ - $ ,000 $ $ 612,361 $ 305,341 $ 307,019 $ ,000 $ $ 305,341 $ - $ 305,341 $ - B. As approved by the BPU on May 23, 2012 in Docket No. GR , NJNG has generated additional BGSS savings of $7.99 million by not renewing 30,000 dth per day of TETCO capacity from STX to M3 at the maximum daily demand rate of $0.73 per dth beginning November 1, (Contract ) Recurring CIP Recovery Release Total Initial Savings Savings from Additional Year Days Quantity Rate Value Identified Extension Savings ,000 $ $ 7,336,500 $ - $ - $ 7,336, ,000 $ $ 7,993,500 $ - $ - $ 7,993, ,000 $ $ 7,993,500 $ - $ - $ 7,993,500

54 Exhibit C Schedule 6 Page 7 of 8 V. Dominion Gas Capacity A. NJNG released 20,000 dth of Dominion capacity from Lebanon to Chambersburg (3,500 dth) and Leidy (16,500 dth). This release is for a term beginning January 1, 2010 through March 31, (Contract ) UPDATE: Release has been extended through March 31, Recurring CIP Recovery Release Total Initial Savings Savings from Additional Year Days Quantity Rate Value Identified Extension Savings ,000 $ $ 696,461 $ 696,461 $ - $ ,000 $ $ 931,166 $ 931,166 $ - $ ,000 $ $ 933,717 $ 933,717 $ - $ ,000 $ $ 931,166 $ 464,307 $ 466,859 $ ,000 $ $ 464,307 $ - $ 464,307 $ - B. As approved by the BPU on April 27, 2011 in BPU Docket No. GR and, NJNG has generated additional BGSS savings of $217,305 for CIP purposes beginning in fiscal year 2012 by not renewing a contract for 10,000 dekatherms per day of winter-season-only firm transportation capacity on Dominion Transmission, Inc., that expired on March 31, (Contract ) Recurring CIP Recovery Release Total Initial Savings Savings from Additional Year Days Quantity Rate Value Identified Extension Savings $ 217,305 $ - $ - $ 217, $ 217,305 $ - $ - $ 217, $ 217,305 $ - $ - $ 217,305 C. As filed in BPU Docket No. GR1206, NJNG has generated additional BGSS savings of $1,032,957 for CIP purposes beginning in fiscal year 2013 by restrucuring a contract and reducing the volume by 20,000 dekatherms per day of firm transportation capacity on Dominion Transmission, Inc. (Contract ) Recurring CIP Recovery Release Total Initial Savings Savings from Additional Year Days Quantity Rate Value Identified Extension Savings ,000 $ $ 1,032,957 $ - $ - $ 1,032, ,000 $ $ 1,032,957 $ - $ - $ 1,032,957 VI. Total of all Savings by Year Recurring CIP Recovery Total Initial Savings Savings from Additional Year Value Identified Extension Savings $ 8,058,378 $ 8,058,378 $ - $ $ 5,516,447 $ 5,516,447 $ - $ $ 13,188,074 $ 5,634,269 $ - $ 7,553, $ 14,887,907 $ 4,218,075 $ 1,426,069 $ 9,243, $ 13,461,838 $ 2,799,799 $ 1,418,276 $ 9,243,762 1 The BGSS savings for the CIP year includes $655,230 for one month of the value of Texas Eastern STX-M3 capacity and $2,774,000 for the annual value of the release of 20,000 dth of Iroquois capacity, both of which were part of the BGSS savings identified in the September 30, 2006 CIP Stipulation.

55 Exhibit C Schedule 6 Page 8 of 8 VII. Agreement with NJRES (UPDATE: Agreement has been extended through March 31, 2014.) A. NJNG and NJRES entered into the following transactions for NJNG's right to call on physical supply at no additional fixed cost. The estimated annual value of the peak day physical call options is $300,000. (1) NJNG and NJRES entered into a transaction providing for the sale of up to 28,600 Dth/day of Transco Z6NNY citygate supply to NJNG. The price for all volumes requested on a monthly basis shall be equal to the first of the month index for Transco Z6 NNY deliveries for the corresponding month as reported in Inside FERC. The price for all volumes requested on a daily basis shall be equal to the midpoint daily index for Transco Z6 NNY deliveries for the corresponding day as reported in Gas Daily. (2) NJNG and NJRES entered into a transaction providing for the sale of up to 20,000 Dth/day of Texas Eastern M3 citygate supply to NJNG. The price for all volumes requested on a monthly basis shall be equal to the first of the month index for Texas Eastern M3 deliveries for the corresponding month as reported in Inside FERC. The price for all volumes requested on a daily basis shall be equal to the midpoint daily index for Texas Eastern M3 deliveries for the corresponding day as reported in Gas Daily. B. NJNG and NJRES entered into an agreement where NJNG will release its Central New York Oil and Gas (Stagecoach Storage) with a total storage capacity of 1,630,990 to NJRES for the period from January 1, 2010 to March 31, NJNG initially transferred the gas in storage to NJRES at NJNG's weighted average cost of gas (WACOG) price at January 1, NJRES will manage the storage and provide delivery to NJNG at NJNG's request at the WACOG price. The WACOG will be reset each October 31st based on the balance at the prior March 31 and ratable injections for April through October at the first of the month index for the Tennessee 500 leg as reported in Inside FERC plus applicable FT transport charges.

56 Exhibit C Schedule 7 Page 1 of 1 NEW JERSEY NATURAL GAS COMPANY CONSERVATION INCENTIVE PROGRAM EARNINGS TEST OCTOBER 1, 2012 THROUGH SEPTEMBER 30, 2013 SIX MONTH ACTUAL, SIX MONTH ESTIMATE BPU DOCKET No. GR1305 Net Income $73,308 (000 s) Less: Net earnings from margin sharing, net of tax 4,141 Other income, net of tax 1,412 Net Income - Earnings Test $67,755 Average Thirteen Month Common Equity 697,424 Actual Rate of Return on Common Equity 9.72%

57 EXHIBIT D CALCULATION OF REVISED BALANCING CHARGE FOR F/Y 2014

58 Exhibit D Page 1 of 1 New Jersey Natural Gas Company Calculation of Balancing Charge $000 Balancing Charge related to Inventory 1 12 month Average inventory balance (TETCO storages and LNG) $42,359 Rate of Return 11.44% Storage Carrying Costs $4,846 % of Peak Related to Balancing 55% Balancing $2,661 Annual Firm Therms (excluding FT) (000) 624,513 Pre-tax Balancing Charge $ Balancing Charge related to Demand Charges 2 Pipeline Demand Charges $110,471 Adjustments (BGSS Incentive Credits) ($21,634) Total $88,837 % of Peak Related to Balancing 53.4% Balancing $47,440 Annual Firm Therms (000) 620,845 Pre-tax Balancing Charge $ Total Balancing Charge Pre-tax Balancing Charge related to Inventory $ Pre-tax Balancing Charge related to Demand Charges $ Total Pre-tax Balancing Charge $ Total After-tax Balancing Charge $ Current After-tax Balancing Charge $ Increase/(Decrease) to After-tax Balancing Charge ($0.0035) Calculation of % of Peak Related to Balancing 000 therms Peak Day Therms 8,530 Average Therms on a January Day 3,975 Balancing Therms 4,555 % of Peak 53.4% 1 2 In accordance with the Board's October 3, 2008 Order in BPU Docket no. GR , the Balancing Charge related to Inventory is not updated on an annual basis. The Balancing Charge related to Demand Charges has been updated to reflect costs included this filing.

59 EXHIBIT E IMPACT OF RATE CHANGES ON TYPICAL CUSTOMERS AND COMPUTATION OF BGSS PRICE FOR F/Y 2014

60 Exhibit E Page 1 of 3 New Jersey Natural Gas Company Net impact of Proposed Rate Changes BPU Docket No. GR1305 F/Y 2014 ($/therm) Price Impact for Group I - Residential Non-Heating Customers Component of Current 1 Proposed Change Pre-tax Post-tax Pre-tax Post-tax Pre-tax Post-tax BGSS BGSS $ $ $ $ $ $ CIP Delivery Price (0.0096) (0.0103) NET IMPACT $ $ $ $ ($0.0096) ($0.0103) Price Impact for Group II - Residential Heating Customers Component of Current 1 Proposed Change Pre-tax Post-tax Pre-tax Post-tax Pre-tax Post-tax BGSS BGSS $ $ $ $ $ $ CIP Delivery Price (0.0105) (0.0112) NET IMPACT $ $ $ $ ($0.0105) ($0.0112) Price Impact for Group III - General Service Small Customers Component of Current 1 Proposed Change Pre-tax Post-tax Pre-tax Post-tax Pre-tax Post-tax BGSS BGSS $ $ $ $ $ $ CIP Delivery Price (0.0251) (0.0269) NET IMPACT $ $ $ $ ($0.0251) ($0.0269) Price Impact for Group IV - General Service Large Customers Component of Current 1 Proposed Change Pre-tax Post-tax Pre-tax Post-tax Pre-tax Post-tax BGSS BGSS Changes Monthly CIP Delivery Price (0.0105) (0.0113) NET IMPACT $ $ $ $ ($0.0105) ($0.0113) Projected Annual Post-tax BGSS, CIP, and WNC revenue BGSS projected annual therms CIP Group I projected annual therms CIP Group II projected annual therms CIP Group III projected annual therms CIP Group IV projected annual therms 423,082 (000s) 3,135 (000s) 445,928 (000s) 33,110 (000s) 134,663 (000s) Projected Revenue at Current Rates Projected Revenue at Proposed Rates Change $million $million $million BGSS $256.2 $256.2 $0.00 CIP Group I $0.0 $0.02 ($0.03) CIP Group II $15.7 $10.7 ($4.99) CIP Group III $2.8 $1.9 ($0.89) CIP Group IV $9.2 $7.6 ($1.52) IMPACT $283.9 $276.5 ($7.44) 1 BGSS rate to be implemented effective June 1, 2013 per the Company's May 24, 2013 notification letter in BPU in Docket Nos. GR and GX

61 New Jersey Natural Gas Company Net impact of Proposed Rate Changes BPU Docket No. GR1305 F/Y 2014 Exhibit E Page 2 of 3 Exhibit E Page 2 of 3 ($/therm) Current 1 Proposed Residential Non- Heat Residential Heat GSS Residential Non- Heat Residential Heat GSS Pre-tax Periodic BGSS $ $ $ $ $ $ After-tax Periodic BGSS $ $ $ $ $ $ Less: Balancing ($0.0898) ($0.0898) ($0.0898) ($0.0863) ($0.0863) ($0.0863) BGSS Price To Compare $ $ $ $ $ $ Impact on Residential Non-Heating Customers Current Prices 25 therm bill Customer Charge $8.25 $8.25 Delivery $ $13.13 BGSS $ $12.90 Total $ $34.28 Proposed prices- effective 10/1/13 Customer Charge $8.25 $8.25 Delivery $ $12.78 BGSS $ $12.98 Total $ $34.01 Decrease ($0.26) Decrease as a percent (0.8%) Impact on Residential Heating Customers Current Prices 100 therm bill 1000 therm annual bill Customer Charge $8.25 $8.25 $99.00 Delivery $ $54.50 $ BGSS $ $51.58 $ Total $ $ $1, Proposed prices- effective 10/1/13 Customer Charge $8.25 $8.25 $99.00 Delivery $ $53.03 $ BGSS $ $51.93 $ Total $ $ $1, Increase ($1.12) ($11.20) Increase as a percent (1.0%) (1.0%) Impact on Commercial GSS Customers Current Prices 100 therm bill Customer Charge $25.00 $25.00 Delivery $ $55.00 BGSS $ $51.58 Total $ $ Proposed prices- effective 10/1/13 Customer Charge $25.00 $25.00 Delivery $ $51.96 BGSS $ $51.93 Total $ $ Increase ($2.69) Increase as a percent (2.0%) Impact on Commercial GSL Customers Current Prices 1200 therm bill Customer Charge $40.00 $40.00 Demand Charge $1.50 $ Delivery $ $ BGSS (May 2013) $ $ Total $ $1, Proposed prices- effective 10/1/13 Customer Charge $40.00 $40.00 Demand Charge $1.50 $ Delivery $ $ BGSS (May 2013) $ $ Total $ $1, Increase ($13.56) Increase as a percent (0.9%) 1 BGSS rate to be implemented effective June 1, 2013 per the Company's May 24, 2013 notification letter in BPU in Docket Nos. GR and GX

62 Exhibit E Page 3 of 3 NEW JERSEY NATURAL GAS COMPANY SUMMARY OF PERIODIC BGSS COMPONENTS BPU DOCKET NO GR1305 ESTIMATED UNDER/(OVER) RECOVERED GAS COSTS AT 10/1/13 (Exhibit B, Schedule 1) ESTIMATED NET COSTS APPLICABLE TO BGSS (Exhibit B, Schedule 2a) October 1, 2013 through September 30, 2014 $000 $46 A $317,075 B ESTIMATED ADJUSTMENTS Interruptible (Sch.4a) $0 Sayreville (Sch.4b) ($34) Forked River (Sch.4c) ($37) Transportation(Sch.4d) ($1,559) FRM Program (Sch 4i) $0 Storage Incentive (Sch. 4k) $0 Off-System Sales (Sch.4e) ($2,833) Capacity Rel. (Sch.4f ) ($18,800) Supplier Ref. and Miscellaneous Adj. (Sch.5 ) $0 Balancing Credits and Penalty Charges (Sch.4g) ($10,925) Ocean Peaking Power (Sch. 4h) ($1,060) TOTAL ADJUSTMENTS ESTIMATED UNDER/(OVER) RECOVERY AT 9/30/2014 (Exhibit B Schedule 1) ($35,249) C $1,754 D A/C Sales Recovery $77 Monthly BGSS Sales Recovery $40,285 FEED $290 ESTIMATED OTHER RECOVERY $40,653 E (Exhibit B Schedule 2b) ESTIMATED TOTAL EXCESS COSTS TO BE RECOVERED (Exhibit B Schedule 2b) $239,464 A+B+C-D-E=F BGSS Sales 483,637 A/C Sales {May - Sep} 170 Monthly BGSS Sales 59,745 FEED 640 ESTIMATED PERIODIC BGSS THERM SALES 423,082 G (Exhibit B Schedule 2b) PRE-TAX PERIODIC BGSS FACTOR PER THERM FOR FY2013 $ F/G=H

63 EXHIBIT F PROPOSED TARIFF SHEETS

64 NEW JERSEY NATURAL GAS COMPANY SixteenthFifteenth Revised Sheet No. 51 BPU No. 8 - Gas Superseding FifteenthFourteenth Revised Sheet No. 51 SERVICE CLASSIFICATION - RS RESIDENTIAL SERVICE Exhibit F Page 1 of 21 AVAILABILITY This service is available to any residential Customer in the territory served by the Company using gas for any domestic purpose. This rate is applicable to individually-metered apartments and to rooming and boarding houses where the number of rental bedrooms is not more than twice the number of bedrooms used by the Customer. Gas delivered under this schedule may not be used for other than domestic purposes except when such use is incidental to domestic use. CHARACTER OF SERVICE Firm gas service where Customer may either purchase gas supply from the Company s Rider A for Basic Gas Supply Service ( BGSS ) or from a Marketer or Broker. MONTHLY RATES Customer Charge: Customer Charge per meter per month $8.25 Delivery Charge: Residential Heating Delivery Charge per therm $ Residential Non-Heating Delivery Charge per therm $ BGSS Charge: BGSS Charge per therm for Sales Customers See Rate Summaries at the end of this Tariff These rates are inclusive of all applicable taxes and riders and are subject to adjustment for all other applicable riders, taxes, assessments or similar charges lawfully imposed by the Company. See Rate Summaries at the end of this Tariff for a summary of components incorporated in these rates. Date of Issue: December 21, 2012 Effective for service rendered on Issued by: Mark R. Sperduto, Senior Vice President and after OctoberJanuary 1, 2013 Wall, NJ Filed pursuant to Order of the Board of Public Utilities entered in Docket No. GR1305 Filed pursuant to the Board s Secretary letter dated December 19, 2012 I/M/O the Phase Out of the Transitional Energy Facility Assessment ( TEFA ) Pursuant to N.J.S.A. 48: (5) and N.J.S.A. 54:30A-102 in Docket No. EO

65 NEW JERSEY NATURAL GAS COMPANY FourteenthThirteenth Revised Sheet No. 54 BPU No. 8 - Gas Superseding ThirteenthTwelfth Revised Sheet No. 54 SERVICE CLASSIFICATION DGR DISTRIBUTED GENERATION SERVICE - RESIDENTIAL Exhibit F Page 2 of 21 AVAILABILITY This service is available to any residential customer using distributed generation technologies including, but not limited to, microturbines and fuel cells to generate electricity for domestic purposes. CHARACTER OF SERVICE Firm gas service where Customer may either purchase gas supply from the Company s Rider A for Basic Gas Supply Service ( BGSS ) or from a Marketer or Broker. MONTHLY RATES Customer Charge: Customer Charge per meter per month $8.25 Delivery Charge: November - April $ May - October $ BGSS Charge: BGSS Charge per therm for Sales Customers See Rate Summaries at the end of this Tariff These rates are inclusive of all applicable taxes and riders and are subject to adjustment for all other applicable riders, taxes, assessments or similar charges lawfully imposed by the Company. See Rate Summaries at the end of this Tariff for a summary of components incorporated in these rates. MINIMUM MONTHLY CHARGE The minimum monthly charge shall be the Customer Charge. Where service is taken for less than one month, the minimum charge will be prorated. BALANCING CHARGE ADJUSTMENTS The Balancing Charge is included in the Delivery Charge and is subject to adjustment in the Company's annual BGSS proceeding. All revenues derived from this Charge will be credited to the BGSS. See Rider A for the current Balancing Charge. Date of Issue: December 21, 2012 Effective for service rendered on Issued by: Mark R. Sperduto, Senior Vice President and after OctoberJanuary 1, 2013 Wall, NJ Filed pursuant to Order of the Board of Public Utilities entered in Docket No. GR1305 Filed pursuant to the Board s Secretary letter dated December 19, 2012 I/M/O the Phase Out of the Transitional Energy Facility Assessment ( TEFA ) Pursuant to N.J.S.A. 48: (5) and N.J.S.A. 54:30A-102 in Docket No. EO

66 NEW JERSEY NATURAL GAS COMPANY SixteenthFifteenth Revised Sheet No. 56 BPU No. 8 - Gas Superseding FifteenthFourteenth Revised Sheet No. 56 SERVICE CLASSIFICATION GSS GENERAL SERVICE - SMALL Exhibit F Page 3 of 21 AVAILABILITY This service is available to any Customer in the entire territory served by the Company who uses less than 5,000 therms annually and uses gas for all purposes other than residential service and interruptible service. Where the Customer uses the Cooling, Air Conditioning and Pool Heating service ( CAC ), the Company will, upon application by the Customer, meter the space heating and CAC use separately. Street Lighting Service also will be supplied under this schedule. CHARACTER OF SERVICE Firm gas service where Customer may either purchase gas supply from the Company s Rider A for Basic Gas Supply Service ( BGSS ) or from a Marketer or Broker. MONTHLY RATES Customer Charge: Customer Charge per meter per month $25.00 Delivery Charge: Delivery Charge per therm $ BGSS Charge: BGSS Charge per therm for Sales Customers See Rate Summaries at the end of this Tariff These rates are inclusive of all applicable taxes and riders and are subject to adjustment for all other applicable riders, taxes, assessments or similar charges lawfully imposed by the Company. See Rate Summaries at the end of this Tariff for a summary of components incorporated in these rates. MINIMUM MONTHLY CHARGE The minimum monthly charge shall be the Customer Charge. Where service is taken for less than one month, the minimum charge will be prorated. BALANCING CHARGE ADJUSTMENTS The Balancing Charge is included in the Delivery Charge and is subject to adjustment in the Company's annual BGSS proceeding. All revenues derived from this Charge will be credited to the BGSS. See Rider A for the current Balancing Charge. Date of Issue: December 21, 2012 Effective for service rendered on Issued by: Mark R. Sperduto, Senior Vice President and after OctoberJanuary 1, 2013 Wall, NJ Filed pursuant to Order of the Board of Public Utilities entered in Docket No. GR1305 Filed pursuant to the Board s Secretary letter dated December 19, 2012 I/M/O the Phase Out of the Transitional Energy Facility Assessment ( TEFA ) Pursuant to N.J.S.A. 48: (5) and N.J.S.A. 54:30A-102 in Docket No. EO

67 NEW JERSEY NATURAL GAS COMPANY SixteenthFifteenth Revised Sheet No. 59 BPU No. 8 - Gas Superseding FifteenthFourteenth Revised Sheet No. 59 SERVICE CLASSIFICATION - GSL GENERAL SERVICE - LARGE Exhibit F Page 4 of 21 AVAILABILITY This service is available to any Customer in the entire territory served by the Company who uses greater than or equal to 5,000 therms annually and uses gas for all purposes other than residential service and interruptible service. Where the Customer uses the Cooling, Air Conditioning and Pool Heating service ( CAC ) under Special Provision 1 applicable to customers purchasing gas supply under Rider A, the Company will, upon application by the Customer, meter the space heating and CAC use separately. CHARACTER OF SERVICE Firm gas service where Customer may either purchase gas supply from the Company s Rider A for Basic Gas Supply Service ( BGSS ) or from a Marketer or Broker. MONTHLY RATES Customer Charge: Customer Charge per meter per month $40.00 Demand Charge: Demand Charge per therm applied to HMAD $1.50 Delivery Charge: Delivery Charge per therm $ BGSS Charge: BGSS Charge per therm for Sales Customers See Rate Summaries at the end of this Tariff These rates are inclusive of all applicable taxes and riders and are subject to adjustment for all other applicable riders, taxes, assessments or similar charges lawfully imposed by the Company. See Rate Summaries at the end of this Tariff for a summary of components incorporated in these rates. MINIMUM MONTHLY CHARGE The minimum monthly charge shall be the Customer Charge and the Demand Charge. Where service is taken for less than one month, the minimum charge will be prorated. Date of Issue: December 21, 2012 Effective for service rendered on Issued by: Mark R. Sperduto, Senior Vice President and after OctoberJanuary 1, 2013 Wall, NJ Filed pursuant to Order of the Board of Public Utilities entered in Docket No. GR1305 Filed pursuant to the Board s Secretary letter dated December 19, 2012 I/M/O the Phase Out of the Transitional Energy Facility Assessment ( TEFA ) Pursuant to N.J.S.A. 48: (5) and N.J.S.A. 54:30A-102 in Docket No. EO

68 NEW JERSEY NATURAL GAS COMPANY SixteenthFifteenth Revised Sheet No. 65 BPU No. 8 - Gas Superseding FifteenthFourteenth Revised Sheet No. 65 AVAILABILITY SERVICE CLASSIFICATION - DGC DISTRIBUTED GENERATION SERVICE - COMMERCIAL This service is available to any commercial customer using distributed generation technologies including, but not limited to, microturbines and fuel cells. CONDITIONS PRECEDENT If the Customer is served by a Marketer or Broker, the Marketer or Broker assumes the responsibility for all delivery requirements. The Customer also must have clear and marketable title of gas with firm transportation capacity to the Company's distribution systems. If the Company so requests, the Customer must provide such proof. The Customer is responsible for payment of any costs if additional facilities, exclusive of metering facilities, are necessary to provide service. The Company reserves the right to limit new customers served under this service, if it determines that service expansion is detrimental to existing firm customers. The Customer must demonstrate that qualifying electric generation equipment has been installed at its location. MONTHLY RATES DGC-Balancing DGC-FT Customer Charge: Customer Charge per meter per month $40.00 $40.00 Demand Charge: Demand Charge per therm applied to PBQ $0.60 $0.60 Delivery Charge per therm: November - April $ $ May - October $ $ The Delivery Charges for DGC-Balancing above include the Balancing Charge as reflected in Rider A of this Tariff for customers whose Marketer or Broker deliver gas on their behalf pursuant to paragraph (1) under Minimum Daily Delivery Volumes section of this Service Classification. For DGC-FT customers whose Marketer or Broker deliver gas on their behalf pursuant to paragraph (2) under Minimum Daily Delivery Volumes section of this Service Classification, the DGC- FT Delivery Charges above exclude the Balancing Charge reflected in Rider A of this Tariff. These rates are inclusive of all applicable taxes and riders and are subject to adjustment for all other applicable riders, taxes, assessments or similar charges lawfully imposed by the Company. See Rate Summaries at the end of this Tariff for a summary of components incorporated in these rates. Exhibit F Page 5 of 21 Date of Issue: December 21, 2012 Effective for service rendered on Issued by: Mark R. Sperduto, Senior Vice President and after OctoberJanuary 1, 2013 Wall, NJ Filed pursuant to Order of the Board of Public Utilities entered in Docket No. GR1305 Filed pursuant to the Board s Secretary letter dated December 19, 2012 I/M/O the Phase Out of the Transitional Energy Facility Assessment ( TEFA ) Pursuant to N.J.S.A. 48: (5) and N.J.S.A. 54:30A-102 in Docket No. EO

69 NEW JERSEY NATURAL GAS COMPANY TwelfthEleventh Revised Sheet No. 71 BPU No. 8 - Gas Superseding EleventhTenth Revised Sheet No. 71 SERVICE CLASSIFICATION - FC FIRM COGENERATION Exhibit F Page 6 of 21 AVAILABILITY This service is applicable to commercial and industrial Customers using gas for the sequential production of electrical and/or mechanical energy and useful thermal energy from the same fuel source as defined in Section 201 of The Public Utility Regulatory Policies Act (PURPA) of The Customer must 1) certify that the cogeneration facility is approved by FERC as a "Qualifying Facility"; 2) sign a Service Agreement; and 3) be in compliance with the terms of N.J.S.A. 54:30A-50 to receive service under this classification. CHARACTER OF SERVICE Firm gas sales or transportation service. MONTHLY RATES Customer Charge: Customer Charge per meter per month $49.49 Demand Charge: Demand Charge per therm applied to MDQ $1.00 Delivery Charge: Delivery Charge per therm $ BGSS Charge: BGSS Charge per therm for Sales Customers See Rate Summaries at the end of this Tariff These rates are inclusive of all applicable taxes and riders and are subject to adjustment for all other applicable riders, taxes, assessments or similar charges lawfully imposed by the Company. See Rate Summaries at the end of this Tariff for a summary of components incorporated in these rates. Date of Issue: October 9, 2012 Effective for service rendered on Issued by: Mark R. Sperduto, Senior Vice President and after October 12, Wall, NJ Filed pursuant to Order of the Board of Public Utilities entered in Docket No. GR

70 NEW JERSEY NATURAL GAS COMPANY Sixty-ThirdSecond Revised Sheet No. 155 BPU No. 8 - Gas Superseding Sixty-SecondFirst Revised Sheet No. 155 RIDER A BASIC GAS SUPPLY SERVICE - BGSS(Continued) Exhibit F Page 7 of 21 PERIODIC BASIC GAS SUPPLY SERVICE (BGSS) CHARGE 1 CLASS APPLICATION CHARGE RS, GSS, and ED sales customers using less than 5,000 therms annually Included in the Basic Gas Supply Charge BALANCING CHARGE $ per therm CLASS APPLICATION CHARGE RS, GSS, GSL, DGC, ED Included in the Delivery Charge $ per therm MONTHLY BASIC GAS SUPPLY SERVICE (BGSS) CHARGE 1 CLASS GSL, FC and ED sales customers using 5,000 therms or greater annually APPLICATION Included in the Basic Gas Supply Charge Effective Date Charge Per Therm May 1, 2012 $ June 1, 2012 $ July 1, 2012 $ August 1, 2012 $ September 1, 2012 $ October 1, 2012 $ November 1, 2012 $ December 1, 2012 $ January 1, 2013 $ February 1, 2013 $ March 1, 2013 $ April 1, 2013 $ May 1, 2013 $ For billing purposes, the Periodic BGSS and Monthly BGSS charges are adjusted for Balancing Charges as presented in the Rate Summaries at the end of this Tariff. Date of Issue: May 24, 2013 Effective for service rendered on Issued by: Mark R. Sperduto, Senior Vice President and after OctoberJune 1, 2013 Wall, NJ Filed pursuant to Order of the Board of Public Utilities entered in Docket Nos. GR and GX

71 NEW JERSEY NATURAL GAS COMPANY TwelfthEleventh Revised Sheet No. 156 BPU No. 8 - Gas Superseding EleventhTenth Revised Sheet No. 156 RIDER A BASIC GAS SUPPLY SERVICE - BGSS(Continued) Exhibit F Page 8 of 21 BGSS SAVINGS COMPONENT RELATED TO THE CONSERVATION INCENTIVE PROGRAM (CIP) IN RIDER I CLASS APPLICATION CREDIT RS, GSS, GSL, FC, and ED sales customers Embedded within the Periodic Basic Gas Supply Charge and the Monthly Basic Gas Supply Charge ($ ) per therm TEMPORARY BGSS RATE CREDIT ADJUSTMENT CLASS APPLICATION CREDIT RS, GSS, and ED sales customers using less than 5,000 therms annually RS, GSS, and ED sales customers using less than 5,000 therms annually RS, GSS, and ED sales customers using less than 5,000 therms annually RS, GSS, and ED sales customers using less than 5,000 therms annually RS, GSS, and ED sales customers using less than 5,000 therms annually Rate Credit Adjustment effective January 1, 2009 through February 28, 2009 Rate Credit Adjustment effective March 1, 2009 through March 31, 2009 Rate Credit Adjustment effective February 1, 2010 through March 31, 2010 Rate Credit Adjustment effective April 1, 2010 through April 30, 2010 Rate Credit Adjustment effective December 1, 2011 through February 29, 2012 and March 15, 2012 through March 31, 2012 ($0.1996) per therm ($0.2510) per therm ($0.2745) per therm ($0.6572) per therm ($0.4419) per therm Date of Issue: October 9, 2012 Effective for service rendered on Issued by: Mark R. Sperduto, Senior Vice President and after October 12, Wall, NJ Filed pursuant to Order of the Board of Public Utilities entered in Docket No. GR

72 NEW JERSEY NATURAL GAS COMPANY FifthFourth Revised Sheet No. 182 BPU No. 8 - Gas Superseding FourthThird Revised Sheet No. 182 RIDER "I" CONSERVATION INCENTIVE PROGRAM CIP (Continued) Exhibit F Page 9 of 21 The currently effective CIP factor by Customer Class Group are as follows: Group I (RS non-heating): $ Group II (RS heating): $ Group III (GSS, ED using less than 5,000 therms annually): $ Group IV (GSL, ED using 5,000 therms or greater annually): $ For the recovery of the October through September CIP margin deficiency, the recovery of the margin deficiency associated with non-weather related change in customer usage included in the above factors are offset by the BGSS savings component, as set forth in Rider A. The BGSS savings component is embedded within the Periodic BGSS Charge and the Monthly BGSS Charge. Date of Issue: October 9, 2012 Effective for service rendered on Issued by: Mark R. Sperduto, Senior Vice President and after October 12, Wall, NJ Filed pursuant to Order of the Board of Public Utilities entered in Docket No. GR

73 NEW JERSEY NATURAL GAS COMPANY NineteenthEighteenth Revised Sheet No. 252 BPU No. 8 - Gas Superseding EighteenthSeventeenth Revised Sheet No. 252 SUMMARY OF RESIDENTIAL RATE COMPONENTS Residential Heating Customers Exhibit F Page 10 of 21 Customer Charge Customer Charge per meter per month Bundled Transport Sales Sales Reference Delivery Charge ( DEL ) per therm Transport Rate: Pre-tax Base Rate TEFA Rider B SUT Rider B After-tax Base Rate WNC Rider D CIP Rider I 240 EE Rider F CNGC Rider G Total Transport Rate a Balancing Charge b Rider A Societal Benefits Charge ( SBC ): NJ s Clean Energy Rider E RA Rider C USF Rider H Total SBC c Delivery Charge (DEL) a+b+c=d Basic Gas Supply Charge ( BGS ) Periodic BGSS e Less: Balancing f BGS e-f=g x x x Rider A Date of Issue: May 24, 2013 Effective for service rendered on Issued by: Mark R. Sperduto, Senior Vice President and after OctoberJune 1, 2013 Wall, NJ Filed pursuant to Order of the Board of Public Utilities entered in Docket Nos. GR and GX

74 NEW JERSEY NATURAL GAS COMPANY NineteenthEighteenth Revised Sheet No. 252 BPU No. 8 - Gas Superseding EighteenthSeventeenth Revised Sheet No. 252 SUMMARY OF RESIDENTIAL RATE COMPONENTS With the exception of the Customer Charge, these rates are on a per-therm basis. Customer Charge, DEL rate and BGS rate are presented on customer bills. Exhibit F Page 11 of 21 Date of Issue: May 24, 2013 Effective for service rendered on Issued by: Mark R. Sperduto, Senior Vice President and after OctoberJune 1, 2013 Wall, NJ Filed pursuant to Order of the Board of Public Utilities entered in Docket Nos. GR and GX

75 NEW JERSEY NATURAL GAS COMPANY Exhibit F Page 12 of 21 NineteenthEighteenth Revised Sheet No. 253 BPU No. 8 - Gas Superseding EighteenthSeventeenth Revised Sheet No. 253 SUMMARY OF RESIDENTIAL RATE COMPONENTS Residential Non-Heating Customers Customer Charge Customer Charge per meter per month Bundled Transport Sales Sales Reference Delivery Charge ( DEL ) per therm Transport Rate: Pre-tax Base Rate TEFA Rider B SUT Rider B After-tax Base Rate CIP Rider I EE Rider F CNGC Rider G Total Transport Rate a Balancing Charge b Rider A Societal Benefits Charge ( SBC ): NJ s Clean Energy Rider E RA Rider C USF Rider H Total SBC c Delivery Charge (DEL) a+b+c=d Basic Gas Supply Charge ( BGS ) Periodic BGSS e x Rider A Less: Balancing f x BGS e-f=g x Date of Issue: May 24, 2013 Effective for service rendered on Issued by: Mark R. Sperduto, Senior Vice President and after OctoberJune 1, 2013 Wall, NJ Filed pursuant to Order of the Board of Public Utilities entered in Docket Nos. GR and GX

76 NEW JERSEY NATURAL GAS COMPANY Exhibit F Page 13 of 21 NineteenthEighteenth Revised Sheet No. 253 BPU No. 8 - Gas Superseding EighteenthSeventeenth Revised Sheet No. 253 SUMMARY OF RESIDENTIAL RATE COMPONENTS With the exception of the Customer Charge, these rates are on a per-therm basis. Customer Charge, DEL rate and BGS rate are presented on customer bills. Date of Issue: May 24, 2013 Effective for service rendered on Issued by: Mark R. Sperduto, Senior Vice President and after OctoberJune 1, 2013 Wall, NJ Filed pursuant to Order of the Board of Public Utilities entered in Docket Nos. GR and GX

77 NEW JERSEY NATURAL GAS COMPANY EighteenthSeventeenth Revised Sheet No. 254 BPU No. 8 - Gas Superseding SeventeenthSixteenth Revised Sheet No. 254 Exhibit F Page 14 of 21 SUMMARY OF RESIDENTIAL RATE COMPONENTS Residential Distributed Generation Service Customer Charge Customer Charge per meter per month Nov - Apr May - Oct Reference Delivery Charge ( DEL ) per therm Transport Rate: Pre-tax Base Rate TEFA SUT Rider B After-tax Base Rate EE Rider F Total Transport Rate a Balancing Charge b Rider A Societal Benefits Charge ( SBC ): NJ s Clean Energy Rider E RA Rider C USF Rider H Total SBC c Delivery Charge (DEL) a+b+c=d Basic Gas Supply Charge ( BGS ) Periodic BGSS e Rider A Less: Balancing f BGS e-f=g With the exception of the Customer Charge, these rates are on a per-therm basis. Customer Charge, DEL rate and BGS rate are presented on customer bills. Date of Issue: May 24, 2013 Effective for service rendered on Issued by: Mark R. Sperduto, Senior Vice President and after OctoberJune 1, 2013 Wall, NJ Filed pursuant to Order of the Board of Public Utilities entered in Docket Nos. GR and GX

78 NEW JERSEY NATURAL GAS COMPANY TwentiethNineteenth Revised Sheet No. 255 BPU No. 8 - Gas Superseding NineteenthEighteenth Revised Sheet No. 255 Exhibit F Page 15 of 21 SUMMARY OF FIRM COMMERCIAL RATE COMPONENTS General Service - Small (GSS) Bundled Transport Sales Sales Reference Customer Charge Customer Charge per meter per month Delivery Charge ( DEL ) per therm Transport Rate: Pre-tax Base Rate TEFA Rider B SUT Rider B After-tax Base Rate WNC Rider D CIP Rider I 581 EE Rider F CNGC Rider G Total Transport Rate a Balancing Charge b Rider A Societal Benefits Charge ( SBC ): NJ s Clean Energy Rider E RA Rider C USF Rider H Total SBC c Delivery Charge (DEL) a+b+c=d Basic Gas Supply Charge ( BGS ) Periodic BGSS e x Rider A Less: Balancing f x BGS e-f=g x Date of Issue: May 24, 2013 Effective for service rendered on Issued by: Mark R. Sperduto, Senior Vice President and after OctoberJune 1, 2013 Wall, NJ Filed pursuant to Order of the Board of Public Utilities entered in Docket Nos. GR and GX

79 NEW JERSEY NATURAL GAS COMPANY TwentiethNineteenth Revised Sheet No. 255 BPU No. 8 - Gas Superseding NineteenthEighteenth Revised Sheet No. 255 Exhibit F Page 16 of 21 SUMMARY OF FIRM COMMERCIAL RATE COMPONENTS With the exception of the Customer Charge, these rates are on a per-therm basis. Customer Charge, DEL rate and BGS rate are presented on customer bills. Date of Issue: May 24, 2013 Effective for service rendered on Issued by: Mark R. Sperduto, Senior Vice President and after OctoberJune 1, 2013 Wall, NJ Filed pursuant to Order of the Board of Public Utilities entered in Docket Nos. GR and GX

80 NEW JERSEY NATURAL GAS COMPANY Seventy-FirstSeventieth Revised Sheet No. 256 BPU No. 8 - Gas Superseding SeventiethSixty-Ninth Revised Sheet No. 256 SUMMARY OF FIRM COMMERCIAL RATE COMPONENTS General Service - Large (GSL) Bundled Transport Sales Sales Reference Customer Charge Customer Charge per meter per month Demand Charge Demand Charge per month applied to HMAD Delivery Charge ( DEL ) per therm Transport Rate: Pre-tax Base Rate TEFA Rider B SUT Rider B After-tax Base Rate WNC Rider D CIP Rider I 568 EE Rider F CNGC Rider G Exhibit F Page 17 of 21 Total Transport Rate a Balancing Charge b Rider A Societal Benefits Charge ( SBC ): NJ s Clean Energy Rider E RA Rider C USF Rider H Total SBC c Delivery Charge (DEL) a+b+c=d Basic Gas Supply Charge ( BGS ) Monthly BGSS e X Rider A Less: Balancing f X BGS e-f=g Date of Issue: April 26, 2013 Effective for service rendered on Issued by: Mark R. Sperduto, Senior Vice President and after OctoberMay 1, 2013 Wall, NJ Filed pursuant to the Order of the Board of Public Utilities entered ins Docket No. GR X

81 NEW JERSEY NATURAL GAS COMPANY Seventy-FirstSeventieth Revised Sheet No. 256 BPU No. 8 - Gas Superseding SeventiethSixty-Ninth Revised Sheet No. 256 SUMMARY OF FIRM COMMERCIAL RATE COMPONENTS Exhibit F Page 18 of 21 With the exception of the Customer Charge and Demand charges, these rates are on a per-therm basis. Customer, Demand, DEL, and BGSS charges are presented on customer bills. Date of Issue: April 26, 2013 Effective for service rendered on Issued by: Mark R. Sperduto, Senior Vice President and after OctoberMay 1, 2013 Wall, NJ Filed pursuant to the Order of the Board of Public Utilities entered ins Docket No. GR

82 NEW JERSEY NATURAL GAS COMPANY SixteenthFifteenth Revised Sheet No. 258 BPU No. 8 - Gas Superseding FifteenthFourteenth Revised Sheet No. 258 SUMMARY OF FIRM COMMERCIAL RATE COMPONENTS Commercial Distributed Generation Service Nov - Apr May - Oct Reference Customer Charge Customer Charge per meter per month Demand Charge Demand Charge per therm per month applied to PBQ Delivery Charge ( DEL ) per therm Transport Rate: Pre-tax Base Rate TEFA SUT Rider B After-tax Base Rate EE Rider F CNGC Rider G Total Transport Rate a Societal Benefits Charge ( SBC ): NJ s Clean Energy Rider E RA Rider C USF Rider H Total SBC c DGC-FT Delivery Charge (DEL) a+b=c Balancing Charge b DGC-Balancing Delivery Charge (DEL) a+b+c=d The Delivery Charges for DGC-Balancing above include the Balancing Charge as reflected in Rider A of this Tariff for customers whose Marketer or Broker deliver gas on their behalf pursuant to paragraph (1) under Minimum Daily Delivery Volumes section of Service Classification DGC. For DGC-FT customers whose Marketer or Broker deliver gas on their behalf pursuant to paragraph (2) under Minimum Daily Delivery Volumes section of Service Classification DGC, the DGC-FT Delivery Charges above exclude the Balancing Charge reflected in Rider A of this Tariff. With the exception of the Customer Charge and Demand Charge, these rates are on a per-therm basis. Date of Issue: December 21, 2012 Effective for service rendered on Issued by: Mark R. Sperduto, Senior Vice President and after October January 1, 2013 Wall, NJ Filed pursuant to Order of the Board of Public Utilities entered in Docket Nos. GR1305 Filed pursuant to the Board s Secretary letter dated December 19, 2012 I/M/O the Phase Out of the Transitional Energy Facility Assessment ( TEFA ) Pursuant to N.J.S.A. 48: (5) and N.J.S.A. 54:30A-102 in Docket No. EO Exhibit F Page 19 of 21

83 NEW JERSEY NATURAL GAS COMPANY SixteenthFifteenth Revised Sheet No. 258 BPU No. 8 - Gas Superseding FifteenthFourteenth Revised Sheet No. 258 SUMMARY OF FIRM COMMERCIAL RATE COMPONENTS Exhibit F Page 20 of 21 Customer Charge, Demand Charge, and DEL rate are presented on customer bills. Date of Issue: December 21, 2012 Effective for service rendered on Issued by: Mark R. Sperduto, Senior Vice President and after October January 1, 2013 Wall, NJ Filed pursuant to Order of the Board of Public Utilities entered in Docket Nos. GR1305 Filed pursuant to the Board s Secretary letter dated December 19, 2012 I/M/O the Phase Out of the Transitional Energy Facility Assessment ( TEFA ) Pursuant to N.J.S.A. 48: (5) and N.J.S.A. 54:30A-102 in Docket No. EO

84 NEW JERSEY NATURAL GAS COMPANY Sixty-SeventhSixth Revised Sheet No. 259 BPU No. 8 - Gas Superseding Sixty-SixthFifth Revised Sheet No. 259 SUMMARY OF FIRM COMMERCIAL RATE COMPONENTS Firm Cogeneration (FC) Exhibit F Page 21 of 21 Sales Transport Reference Customer Charge Customer Charge per meter per month Demand Charge Demand Charge per therm per month applied to MDQ Delivery Charge ( DEL ) per therm Transport Rate: Pre-tax Base Rate SUT Rider B After-tax Base Rate EE Rider F Total Transport Rate a Balancing Charge b Rider A Societal Benefits Charge ( SBC ): NJ s Clean Energy Rider E RA Rider C USF Rider H Total SBC c Delivery Charge (DEL) a+b+c=d Basic Gas Supply Charge ( BGS ) Monthly BGSS e X Rider A Less: Balancing f X BGS e-f=g X With the exception of the Customer Charge and Demand Charge, these rates are on a per-therm basis. Customer Charge, Demand Charge, DEL rate and BGS rate are presented on customer bills. Date of Issue: April 26, 2013 Effective for service rendered on Issued by: Mark R. Sperduto, Senior Vice President and after OctoberMay 1, 2013 Wall, NJ Filed pursuant to Order of the Board of Public Utilities entered in Docket No. GR

85 NEW JERSEY NATURAL GAS COMPANY DIRECT TESTIMONY AND EXHIBITS OF JAYANA S. SHAH DIRECTOR - GAS SUPPLY NJNG ENERGY SERVICES

86 IN THE MATTER OF THE PETITION OF NEW JERSEY NATURAL GAS COMPANY FOR THE ANNUAL REVIEW AND REVISION OF ITS BASIC GAS SUPPLY SERVICE (BGSS) AND CONSERVATION INCENTIVE PROGRAM (CIP) FACTORS FOR F/Y 2014 BPU DOCKET NO. GR1305 Direct Testimony of Jayana S. Shah I. Background and Purpose Q. PLEASE STATE YOUR NAME, AFFILIATION AND BUSINESS ADDRESS. A. My name is Jayana S. Shah. I am the Director, Gas Supply for New Jersey Natural Gas Company (the Company or NJNG ). My business address is 1415 Wyckoff Road, Wall, New Jersey Q. PLEASE DESCRIBE YOUR EDUCATION, YOUR BUSINESS EXPERIENCE, AND YOUR RESPONSIBILITIES WITH RESPECT TO THIS PROCEEDING. A. I received a Bachelor of Science degree in Biology with a Chemistry Minor from the University of Houston in Upon graduation I was employed by Engage Energy in Houston, Texas as a gas settlements specialist and within a year moved into a risk analyst position. My responsibilities as a risk analyst at Engage Energy included reviewing all transactions and reporting profit and loss. When Engage Energy subsequently merged with El Paso Merchant Energy ( El Paso ), I was employed by El Paso as a risk analyst with additional responsibilities, including confirming financial transactions with brokers and validating trader s marks with third party sources. My position at El Paso also provided me with the opportunity to learn about other commodities, including natural gas liquids, crude oil, emission credits, weather derivatives, and currency. I moved to New Jersey in 2003 and was employed by Morgan Stanley in New York for two years as an associate controller responsible for financial reporting for their capital structure arbitrage book and securitized products book. I joined New Jersey Resources ( NJR ) in June 2005 as a trading analyst for NJR Energy Services ( NJRES ), an unregulated affiliate of the Company. My responsibilities there included supporting the trading group with trade and price analysis, working with the Vice President to manage the NJRES portfolio, and creating efficiencies by working with the software programmers and accounting/risk management group.

87 Direct Testimony Jayana S. Shah I was promoted to the position of Manager, Gas Supply for NJNG in May 2009 and to Director, Gas Supply in January In that capacity I oversee the NJNG Energy Services staff for daily, monthly, and seasonal optimization of NJNG s supply portfolio in order to provide the lowest overall cost for the Company s Basic Gas Supply Service ( BGSS ) customers. I also oversee the Company s BGSS hedging and incentive programs that provide price stability and cost savings for BGSS customers. Q. HAVE YOU PREVIOUSLY TESTIFIED IN REGULATORY PROCEEDINGS? A. Yes. I have testified on behalf of NJNG in numerous BGSS proceedings before the New Jersey Board of Public Utilities (the BPU or Board ). Q. WHAT IS THE PURPOSE OF THIS TESTIMONY? A. Consistent with the Board Order dated January 17, 2002 in Docket No. GX ( Generic BGSS Order ), the purpose of my testimony is to: discuss current conditions in natural gas markets that may affect the Company s BGSS pricing and BGSS incentive programs; and describe and detail how the Company actively manages and optimizes its gas supply and capacity portfolio on a daily, monthly and seasonal basis throughout the year to provide reliable service to customers at a reasonable cost, including steps it has taken to hedge its projected BGSS winter period sales requirements; and provide the basis for and a narrative explanation of the significant drivers of the BGSS rate which the Company is proposing through this proceeding to be approved and effective October 1, I am also sponsoring a number of exhibits that provide the requisite detail and support for the projected gas costs and forecasted sales in this case consistent with the annual Minimum Filing Requirements ( MFRs ) that were established in the Generic BGSS Order. Q. HOW IS THE BALANCE OF YOUR TESTIMONY ORGANIZED? A. The balance of my testimony is organized as follows: Section II: Current Market Conditions and Impact to BGSS Section III: Optimization Strategy Section IV: Periodic BGSS Pricing for October 1, 2013 Section V: MFR Supporting Data and Information

88 Direct Testimony Jayana S. Shah Section VI: Conclusion II. Current Market Conditions and Impact to BGSS Q. PLEASE DESCRIBE ANY CHANGES IMPACTING AVAILABLE NATURAL GAS SUPPLIES. A. Over the last several years, natural gas production from unconventional sources, such as shale, has fundamentally changed the gas supply and transportation infrastructure in the United States and will continue to do so. United States dry natural gas production grew by 11.3 Bcf/day, or 15%, between 2009 and Marcellus Shale production as of May 2, 2013 was 8.3 Bcf/day 2. Eight regional pipeline expansions with nearly 2 Bcf/day of capacity came online in late 2012, setting the stage for continued growth in Marcellus Shale production has begun to displace traditional gas supplies from Canada, Mid-Continent, and Gulf of Mexico and expansion projects have been announced by interstate pipelines to deliver the increasing Northeast production to these regions. Twenty-one pipeline projects are planned in the northern region in 2013 and 2014 that would provide 9 Bcf/day of new pipeline capacity Bentek U.S Natural Gas Production Outlook: Believe the Shale Boom. 2 Bentek Weekly Northeast Observer published May 2, 2013